A research team in San Diego says it has developed a new method for recycling lithium-ion batteries in California as electric vehicle and energy storage sales boom across the world.
University of California, San Diego researchers demonstrated how to deactivate, dismantle and separate used battery components to recover more than 90% of cathode and anode active materials. The recycled materials were then tested and found to operate comparably to new battery materials, the researchers said in an Oct. 20 report to the California Energy Commission.
More than 22 million pounds of lithium-ion batteries will be ready for recycling in California in 2027. Without sustainable management, the rapid consumption of batteries “risks resource shortages and price volatility for critical materials like lithium, cobalt and nickel — key contributors to battery costs,” researchers said in the report.
Recycling and recovery of these valuable materials, which can make up 45 to 60% of battery manufacturing costs, are “essential to lowering production expenses and reducing the lifecycle environmental hazards posed by improper disposal,” the report says.
In their experiment, researchers created a direct recycling method to physically separate and recover cathode and anode battery materials. They de-energized 25 pounds of lithium-ion battery cells with more than 1,000 ampere-hours of total capacity. The battery cells contained different chemistries, types, ages and sources, such as from EVs and electronic devices.
The direct recycling method is one of three primary battery recycling methods, the other two being pyrometallurgical recycling and hydrometallurgical recycling.
Pyrometallurgical recycling requires high-temperature smelting that uses large amounts of energy and generates significant pollutants, while hydrometallurgical recycling requires strong acids and oxidants, leading to “extensive treatment to address environmental and safety concerns,” the report says.
Direct recycling could save up to $17 million and reduce energy consumption by up to 1,285 GWh by 2030, compared to pyrometallurgical and hydrometallurgical recycling, the report says.
After proving their direct recycling approach worked, researchers increased the volume of batteries in each batch from 100 g to 5 kg.
California currently does not have a large-scale lithium battery recycling facility. As they grow old and fizzle out, used battery volumes will continue to increase, and the costs of transporting them out of the state will become too burdensome and expensive, the report says.
Battery manufacturers and automakers could leverage an in-state recycling pathway to “enhance efficiency, minimize waste and support the broader electrification of the automotive industry,” the report says.
The results of the project could help future research teams or companies build a 100-kg scale recycling facility. Doing so could be the next step toward building a commercial facility in the state, the report says. UC San Diego researchers have been allocated $10 million by the Department of Energy to continue to increase the scale of the direct recycling method.
NERC Chief Engineer Mark Lauby told attendees at FERC’s annual Reliability Technical Conference that resource adequacy remains a top priority as the industry anticipates rapid demand growth from data centers and other large loads.
Lauby highlighted some of NERC’s work on the large loads issue, including a Level 2 alert sent to industry in September with guidance on “what you need to be thinking about when you’re interconnecting the load, what … kind of data you should be collecting, what kind of studies you should be creating [and] what kind of interconnection standards you should be considering.”
During the Oct. 21 panel, Lauby also brought up the work of NERC’s Large Loads Task Force, which recently submitted a paper on Characteristics and Risks of Emerging Large Loads for comment from the ERO’s Reliability and Security Technical Committee. Lauby said that when the paper is completed later in 2025, it will form the basis of a reliability guideline along with the responses to NERC’s Level 2 alert. That guideline will, in turn, be “the basis for any kind of standards” regarding registering such loads.
“We believe that we can register large loads because of [their] impact to reliable operation of the [grid],” Lauby said. “Obviously, we’ll use judgment on that. It’ll be risk-based, and we’ll work with [the Large Loads Task Force] to write the standards we’re talking about today — for example, communications during events, when you’re going to come off [and] come on, [and] how do you manage the inverter-based resources?”
Lauby’s fellow panelist, Dominion Power Vice President Matt Gardner, said he was “very pleased to see how the industry has come together” on the LLTF. He said the work of the task force has raised Dominion’s awareness of the issues involved; for example, the company incorporated the LLTF’s data center questionnaire and provisions on ride-through protection into its facility interconnection requirements.
Gardner added that another “extremely important” topic discussed by the LLTF concerns implementing high-quality monitoring of the new large loads’ behavior to provide situational awareness and to help create accurate models for planning purposes. This is needed to help grid planners comprehend the unique risks posed by these new arrivals.
“We’ve had large loads on the system forever: paper mills, steel mills, chip [fabricators], you name it,” Gardner said. “But this type of large load is different in terms of how it can behave in somewhat of a synchronized fashion, and in how the internals change over as well.”
FERC Commissioner Lindsay See picked up on this, observing that “large loads are not created equal.” She asked panelists to go into more detail on the various types of large loads and the reliability risks they can present.
Lauby agreed that “size certainly is not the whole thing” and mentioned several issues that can separate one kind of large load from another, such as their behavior during system events and sensitivity to voltage and frequency changes.
Jennifer Curran, senior vice president for planning and operations at MISO, advocated for a risk-based approach that recognizes that the level and type of risk presented by a load depends on a number of factors beyond its size, such as where it is on the grid and how resilient the grid is.
QTS Data Centers Vice President for Energy and Sustainability Travis Wright agreed that the location of a load matters, stating that “the term that resonated with me was ‘material impact.’”
Chris Matos, strategic negotiator for energy markets at Google, also expressed support for a risk-based strategy but urged the commission and ERO not to place overly onerous reporting requirements that restrict companies’ freedom of movement.
“The question has become, for [RTOs], how much administrative work or burden is that below a certain level as well, and do we recreate the log jams that we’re feeling today?” Matos said. “So, I do think a risk-based approach is necessary, and it should do the best that it can, but exact accuracy may not be as important, provided we also think about revisiting that [assessment] over time.”
PJM has promoted a trio of executives while it continues its search for a new CEO.
“This new structure will strengthen our executive team and allow the incoming CEO to focus early on the external work of building strong relationships with stakeholders, regulators and state leaders, and navigating the evolving energy landscape,” David Mills, chair of the RTO’s Board of Managers, said in an announcement of the leadership changes. (See PJM CEO Manu Asthana Announces Year-end Resignation.)
Stu Bresler was elevated to COO from executive vice president of market services and strategy, putting him in charge of core departments such as operations, markets and planning. He has been with the RTO for more than 30 years.
Executive Vice President of Operations, Planning and Security Aftab Khan was promoted to chief strategy officer, setting him up to “lead cross-functional initiatives and drive organizational transformation to ensure sustainable success and alignment,” according to the announcement. He served as senior vice president of engineering for Eversource Energy before joining PJM in 2024 and previously worked at General Electric and ABB.
Vice President of Market Design and Economics Adam Keech was made senior vice president of market services. He has been with PJM since 2003, having overseen NERC compliance and real-time market operations, among other roles.
PJM spokesperson Jeff Shields said the new titles redefine the three executives’ duties, and the prior positions will not be backfilled. He noted that PJM’s last COO was Mike Kormos, who left in 2016. (See PJM COO Kormos Leaving; Post Won’t be Filled.)
The announcement also said the search for a replacement for Manu Asthana, who serves as president and CEO, is proceeding. He announced his resignation April 14, with the intention for it to be effective at the end of 2025.
If a new CEO is not in place by Jan. 1, 2026, Mills will take over as interim president and CEO while the search continues.
“The board is committed to finding the best candidate to lead PJM through the numerous challenges facing the industry, and that meticulous process continues,” Mills said in the announcement.
SIOUX FALLS, S.D. — At a time when MISO’s long-term planning is under fire, the Organization of MISO States’ annual meeting featured speakers who vouched for the power of planning.
MISO Vice President of System Planning Aubrey Johnson said exploding load growth makes the RTO’s long-range transmission planning even more relevant. He also said the rigor MISO applies to its scenario-based transmission planning makes ensuing projects a “least-regrets” route.
Speaking at the Oct. 21 event, Johnson said a single data center can “sign on the dotted line” and alter a load-serving entity’s integrated resource plan. He cautioned the industry against making “knee-jerk reactions” to policy changes and new reliability assessments.
“It doesn’t mean that when those decisions were made three years ago, they were wrong,” he said of grid planning. “I would encourage us to have a little more patience and see this as a signal.”
Johnson said when MISO refashioned its 20-year transmission planning futures in 2019, growing load was a concern. By 2022, flat load estimates influenced an update of the RTO’s futures.
“Both of those cases have prepared us for the generation coming online,” Johnson said of the latest upswing in load forecasts, which are set to shape more long-term transmission planning from the RTO.
Johnson said MISO’s work to install a 765-kV backbone through its long-term planning apparently has inspired neighbors PJM and SPP to draw up their own plans.
But MISO’s second, $22 billion long-range transmission portfolio has attracted criticism in the latter half of 2025.
Terry Wolf, COO of Missouri River Energy Services, said he worries his territory — which exists at the MISO-SPP seam in Iowa, Minnesota, North Dakota and South Dakota — risks being left behind between the RTOs’ separate 765-kV plans. He asked that the RTOs pay attention to the burgeoning chasm at their boundaries and plan interregional links.
“Two regions that are tightly intertwined, in my opinion, must do that,” Wolf said.
Clint Savoy, SPP manager of interregional strategy and engagement, said his RTO’s burgeoning 765-kV portfolio likely eventually would lead to both grid operators examining how to best connect their high-voltage networks.
“I think we’ll have an opportunity to do that over the next few years,” Savoy said.
Outgoing OMS President Joseph Sullivan, a member of the Minnesota Public Utilities Commission, said he’s excited about the prospect of MISO tapping into the West through interregional transmission. He said new transmission routes could deliver more reliability benefits, more diverse resources and economic advantages.
“From my perspective, it’s absolutely worth a deep conservation: How do we look further West?” Sullivan said.
OMS spent much of 2025 in “reactive mode” responding to others’ decisions, Sullivan continued. He referred to MISO’s multibillion-dollar transmission planning, the RTO’s interconnection queue fast lane, explosive load growth and federal policy whiplash.
“The agenda was often set for us,” Sullivan said. He urged OMS in 2026 to “carve out space to truly set our own active agenda” in the face of immense change. “This coming year will test our cohesion,” he told his fellow state regulators.
Christina Drake, MISO’s director of economic, interregional and policy planning, said the RTO’s 765-kV plans can support about 100 GW of generation and provide a foundation for interregional planning.
Drake added that stakeholder meetings can get “spicy” when RTOs start debating the benefits of transmission investment. But she said stakeholders who aren’t motivated by the prospect of expanded transfer capability alone might be persuaded by a “confluence” of increased transfers plus reliability benefits plus congestion-saving benefits. She said outlining the multiple benefits of transmission solutions is paramount after engineering analyses are completed.
However, Drake argued, affordability matters more to MISO South members, regulators and ratepayers than in the RTO’s northern regions.
“The best transmission [projects] are the ones folks are willing to pay for and can be sited. That’s a tall order,” she said.
Wisconsin Public Service Commissioner Marcus Hawkins said the best case for transmission could be the “undeniable value” it provides during widespread extreme weather events.
Savoy said it’s important to figure out how to quantify the resilience benefits, noting that as more time passes between lived events, the more the perceived value of transmission solutions fades. As an example, he said the premium that civilians and utilities placed on continued supply and power restorations during February 2021’s Winter Storm Uri changed dramatically just a few years later.
Ryan Fedie, founder of consulting firm Axelergy, said the “whipsawing” between presidential administrations makes grid investments a tough call. He said that instead of “speed to market,” the Trump administration is fomenting “speed to mistrust.”
Fedie said he wants to make sure the system is expanded adequately and includes distributed energy resources and demand-side options to avoid overbuilding. He said the existing system “was built on a different model in a different era.”
Chelsea Loomis, the Western Power Pool’s regional transmission planning services manager, said there’s much to tackle regarding coordination on load and generation projections. She said when she worked at Northwestern Energy, the utility fielded about 10 separate interconnection requests from a single customer concerning the same load. Data centers, Loomis warned, can utility shop and “FUBAR” load projections and generation plans.
Loomis joked that she was grateful she was not that close to the audience before saying regulators should be doing more to demand more standardized growth information. She said there’s a lot of flexibility in commissions’ reporting requirements.
Johnson said meeting the moment of load growth paired with the energy transition is not “one quantum shift, but a series of incremental shifts.” He said MISO’s work on load projections, resource adequacy assessments and transmission planning often produces a “tension” between it and its members that shapes solutions. He told regulators to expect more work from the RTO on interconnection queue to speed up interconnections to the expanding system.
“Nobody’s talking about how bored they are,” Johnson joked of the zeitgeist in the energy industry.
GE Vernova is moving to expand the reach of its fastest-growing business segment, Electrification, by acquiring full ownership of grid equipment supplier Prolec GE.
The company and its corporate predecessor, General Electric, have held a 50% stake in the transformer manufacturer through a joint venture with Mexico-based Xignux since 1995. In their Oct. 21 announcement, the partners said the $5.3 billion deal is expected to close in mid-2026.
GE Vernova CEO Scott Strazik led off the third-quarter earnings call Oct. 22 with discussion of the acquisition, which he said will provide multiple benefits for the company amid surging U.S. power demand.
Full ownership will remove contractual constraints, allow better control over pricing and strategy, provide a better customer experience and pave the way for integrated solutions, Strazik said. It also provides one more entry point to the data center market.
“We have talked recently about our expected higher R&D next year to develop and deliver more product to data centers, and going beyond the transmission substations we provide today,” Strazik said. “Prolec will help deliver an even more robust range of product offerings.”
Prolec is expected to produce an EBITDA margin of approximately 25% in 2025, and its 2028 revenue is projected to be 40% higher than 2025.
GE Vernova reported third-quarter 2025 income of $453 million ($1.64/share) on $10 billion in revenue.
Of the three business segments:
Power had the largest numbers: $7.8 billion in orders, $4.8 billion in revenue and $84.1 billion backlog.
Electrification had the strongest growth, with an EBITDA margin of 15.1% compared with 10.4% in the same quarter of 2024.
Wind brought up the rear, with improved profitability and decreased offshore losses, but a negative EBITDA of $61 million.
Strazik said market interest in gas power continues unabated: GE Vernova signed 12 GW of new contracts in the third quarter after signing 9 GW in the second quarter. The backlog of gas turbine orders grew from 29 GW to 33 GW, and manufacturing slot reservations increased from 25 to 29.
“We now expect to approach 70 GW of contractual gas power commitments by the end of ’25 with significant momentum into ’26,” he said.
An analyst asked about indications that demand for new turbines may be peaking and that asking prices are starting to be more negotiable.
Strazik said the company is not softening on its asking price, although its order book for any given quarter may not be an accurate barometer.
“In the third quarter, as an example, we had substantially more smaller gas turbines, more aeroderivatives, that are a higher price per megawatt than the baseload units,” Strazik said. “In totality, we continue to see price accelerating in gas,” he said, pointing to the higher prices and better profit margins for the slot reservations that he expects to progress to contracted orders in the next 12 months.
The larger gas turbines are much more economically efficient, he said, but there is a near-term surge in demand that the smaller units will meet. He predicted the aeroderivative and other small gas-fired generators would bridge the need for power until heavy-duty units are available, then convert to backup roles.
LITTLE ROCK, Ark. — Golden Spread Electric Cooperative says it will request that SPP’s Board of Directors overturn a stakeholder group’s rejection of a proposed tariff change that would pre-emptively determine the amount of load the existing transmission system can handle without requiring additional network upgrades.
Golden Spread’s Mike Wise brought the appeal of the tariff revision request (RR642) to the Markets and Operations Policy Committee during its Oct. 14-15 meeting after it gained only 18% approval at the Transmission Working Group in September.
His motion to enable transmission customers and host transmission owners to access load-hosting capacity assessment results failed with only 29.51% approval. SPP’s TO members united to vote against the change, 18-0, after citing concerns at TWG over reliability issues with sharing load-hosting capacity and creating operational risks.
A dejected Wise told RTO Insider after that he again will appeal RR642 during the board’s Nov. 4 meeting. He also will provide a second or alternative motion for the directors’ consideration.
“The TWG got it wrong, and we want to try to rectify that,” Wise told MOPC. “The bottom line is that we support the SPP staff’s position on this RR.”
Staff drafted the proposed change to tariff Attachment AQ’s screening process following a recommendation from the Holistic Integrated Tariff Team’s (HITT) 2019 report. It would allow SPP to proactively perform analysis to determine load capacity at each node on the system without incremental investment. Information gathered from the load-hosting capacity assessment would determine whether transmission customers would be required to go through an AQ delivery point network study.
Wise, who sat on the HITT, sponsored the recommendation during the team’s work. He referred to the proposal as “one of those ancient HITT items that has lingered out there.”
“This gives transmission customers … the same access to the tool and the information as the TOs themselves,” Wise said. “It’s not being crammed down on them. They own the trump card. Basically, if they say we need to study this, then it’s going to be studied, right? I really don’t see why the TOs would be against this because they are not going to have to be forced to do something that doesn’t work or affects their reliability.”
“We are supportive of this tool being used for information purposes, and we just do not feel it’s ready for the decision-making process for AQ studies,” said Jarred Cooley, with Xcel Energy subsidiary Southwestern Public Service.
“This is just a tool with information. The question is, who should see it and what’s the accuracy?” SPP’s Natasha Henderson said. “Just like any other tool with information, it’s predicated on what we put in that tool. On the [generator interconnection] side, we have a tool that shows where there’s room on the system. Well, that’s true until you study 90 GW of generation in the 2024 [Integrated Transmission Plan assessment].”
SPP Close to Resettling Z2 Bills
SPP’s five-year plan to resolve its Attachment Z2 headache — the “most litigated, drawn-out process we’ve ever had,” according to General Counsel Paul Suskie — will begin in earnest in November.
As part of FERC’s directive to submit a compliance filing on its Z2 plan, staff will provide updated balances to entities affected by a 2019 remand order for the refund period (March 2008-August 2015). They will send information to entities wishing to enroll in a payment plan and post ongoing updates on the SPP website.
The commission in September ordered the compliance filing for the grid operator’s proposal to unwind credit payment obligations assessed under Z2 for transmission service taken from 2008 to 2016. The commission determined that SPP lacked specifics in its proposed plan (ER16-1341). (See FERC Requires Additional Z2 Filing from SPP.)
Under Attachment Z2, SPP compensates upgrade sponsors who pay for upgrades that subsequently are used by transmission customers. FERC issued a remand order that called for the refund of Z2 amounts settled and invoiced for operating periods in 2008-2015.
Full refund invoices for the 2008-2015 period will go out within the first two months after FERC’s final order. A resettlement invoice will follow in about two years for the operating dates from September 2015 to January 2020. It will take several years after that to run additional resettlements in the current settlement system until SPP catches up.
Staff told FERC in September 2024 that at least $657.8 million is directly affected by the commission’s refund directive and that it grows by $3 million to $4 million each month.
“Every month that we can’t make our repayment is more interest that our members are paying and we have no return on,” Western Farmers Electric Cooperative’s Matt Caves said.
SPP has assembled more than a dozen executives and staffers to handle the process. As Suskie said, alluding to the Blues Brothers in their eponymous 1980 flick, “We’re getting the band back together.
“It took us eight years to put Z2 together. Now, we’ve got to unwind it and put it back together,” he added.
Staff are planning a formal kickoff for the effort in January 2026. They expect the effort to take about four years.
West Gets Stakeholder Group Seats
MOPC endorsed expanding six working groups to add members from the RTO’s expansion into the Western Interconnection. The vote slipped past MOPC’s two-thirds threshold for approval at 67.24%.
If the measure is approved by the Corporate Governance Committee (CGC) and then the board in November, the Market, Economic Studies, Operating Reliability and Supply Adequacy working groups would get four more seats, and the Members Committee, Strategic Planning Committee and Resource and Energy Adequacy Leadership (REAL) Team will pick up two seats each. The Regional Tariff and Transmission working groups will add TOs and transmission users according to their charters.
The RTO expansion will add seven Western entities, including several that already are members in SPP’s Eastern Interconnection footprint. Members with load in the East won’t be counted toward the new seats, staff said.
An earlier attempt to amend the motion from the floor and limit Western representatives to two seats apiece in the working groups failed, garnering just under 50% approval. Several members pushed back against taking up the issue, saying it belongs in the CGC.
“Vacancies on working groups don’t come up terribly often, so to get entities on board and through this process is a starting point,” said Brad Hans, with the Municipal Energy Agency of Nebraska. The agency will be active in both interconnections.
“It’s a good integration thing,” he said. “There are a lot of differences in the West with us working on both sides, where you need that expertise in the West to bring to the conversations when there are things that may affect both sides.”
SPP’s Steven Johnson, senior director of markets administration, said the RTO expansion project remains on schedule, having moved from red to yellow status at the end of September. Bid-to-bill member testing, a key milestone, began Sept. 2 and is ongoing, he said.
MMU: Topology Optimization Concerns
Stakeholders endorsed the Market Working Group’s expansion of the economic topology optimization process that enables market participants to submit requests for SPP to screen, evaluate and, if they pass both economic and reliability criteria, coordinate with transmission operators for implementation.
The change sets submission limits to one per participant/month, six studies per month and up to three active implementations.
The Market Monitoring Unit said it supports the concept but had “serious concerns” with allowing the requests to come from market participants. Carrie Bivens, the MMU’s vice president, said MISO tried a similar process but it “reported very low success rates” with being able to accept the proposals.
“Not only could it result in suboptimal results, but it’s also a clear fairness issue,” she said. “We believe the RTO should be doing this optimization rather than taking it through stakeholders and through market participant requests. Just from a practical standpoint, it could be a real waste; an inefficient use of SPPs time.”
The measure passed with 90.8% approval.
The committee also endorsed two recommended tariff changes from working groups:
RR719, from the Cost Allocation Working Group, which would base-plan fund network upgrades for network resource interconnection service (NRIS). The proposed change aligns cost allocation for deliverability by allowing the delivery portion of NRIS before the transition to the Consolidated Planning Process to also be eligible for base-plan funding. MOPC gave it 88.2% approval.
RR697, from the MWG, codifying a policy approved by the Regional State Committee to give market participants more opportunities to receive long-term congestion rights (LTCRs). Eligible participants will be able to nominate up to 50% of each path, with all current awarded LTCR paths over 50% grandfathered. The awarded LTCRs can be held for five years. RR697 passed with 72.6% approval.
Ross Exits as MWG Chair
MOPC members honored American Electric Power’s Richard Ross with a round of applause as he delivered the MWG’s final proposed tariff changes under his chairmanship.
Ross has served as chair of the MWG, one of the more influential stakeholder groups, since 2004. That was the year FERC designated SPP as an RTO. Recent governance changes have placed term limits on working groups’ leadership positions.
“I’ve been involved in SPP things for issues from 12 [to] 15 years, and you have been a longstanding chair of the Market Working Group. A lot has passed under your purview,” Omaha Public Power District’s Joe Lang said.
SPP’s Carrie Simpson, who once served as the MWG’s staff secretary, said she has used Ross’ chairmanship as an example to follow in designing the stakeholder structure of Markets+ in the Western Interconnection.
“I know you’ve seen a lot of staff come through and a lot of members,” she told Ross. “As we were setting up working groups in the West, we would say, ‘Watch Richard Ross. The MWG chair is a great standard for how to run a meeting.’
“But you’ve had 20 years of practice,” Simpson cracked.
the Project Cost Working Group’s recommendation to accept all 10 transmission projects with in-service delays exceeding the first reported in-service date by more than 90 calendar days be accepted as reasonable;
the PCWG’s endorsement of a 31% increase in Nebraska Public Power District’s 345-kV Gentleman-Cherry County-Holt County project, from $510.71 million to $669.97 million;
the 2026 ITP-CPP transmission assessment’s revised scope to add the Expedited Resource Adequacy Study’s stability needs;
the TWG’s endorsement of OPPD’s sponsored upgrade study for Sarpy County uprates; and
The agenda also had 20 proposed tariff changes that, if approved by the board, would:
RR655: establish outage submission requirements in SPP’s governing documents, including definitions, data standards, timelines and rules for submission, extension and updates. The change would require market participants to provide accurate, timely outage and capability information, with the transmission provider reviewing and potentially denying noncompliant submissions.
RR670: clarify that a mitigated offer is defined as equality along with its allowable subcomponents and must be interpreted as such when calculated and submitted by market participants.
RR682: add transparency to the competitive transmission process’ TO selection process by requiring the industry expert panel to respond to questions from the board or submitted by stakeholders.
RR686: clarify the difference between ramped and stepped setpoints with consolidated examples, removing outdated quick-start terminology for improved clarity and consistency.
RR690: define the tariff-required harm test to reallocate at-risk financial security funds during the generation-interconnection study process to mitigate harm done by terminating generator interconnection agreements.
RR695: establish thresholds for mitigating offers below $25/MWh, aligning them with correct mitigation practices.
RR700: raise the notification-to-construct (NTC) with conditions and the applicable project threshold limit from $20 million to $150 million.
RR705: update the Generator Interconnection Manual (BP7250) with the Joint Targeted Interconnection Queue’s tariff language.
RR706: clarify that a federal service exemption transfer point is a qualifying source for candidate LTCRs/auction revenue rights (ARRs) by adding the transfer point to the list of qualifying sources for candidate LTCRs/ARRs.
RR707: revise the conventional resource performance-based accreditation business practice without changing FERC’s foundational policy.
RR708: ensure the detailed project proposal window for transmission planning is not unnecessarily extended if additional needs are identified after the needs assessment’s posting.
RR709: ensure the annual index of grandfathered agreements is accurate.
RR710: automatically suspend Attachment AQ upgrade projects with NTCs if the large load is not submitted within 180 days of board approval. SPP would then conduct an out-of-cycle re-evaluation and bring it to the board for its consideration.
RR711: formalize the outage-coordination methodology as a business practice and incorporate it into the revision request routing criteria, requiring applicable working group approval for future changes.
RR712: increase the financial commitment window for SPP’s NTC issuances from four years to five years.
RR713: add language to the tariff including Stegall DC tie equipment in the incremental market efficiency use (IMEU) framework, ensuring transparency, stakeholder review and clarification that replacement costs are not tied to IMEU.
RR715: outline the study requirements used in the quarterly analysis to determine the maximum amount of capacity available for generators under the limed operation condition until network upgrades come online.
RR716: clean up items related to the RTO expansion’s DC ties, including calculations using their capability for cost allocation and DC tie inputs in market cases and the reliability unit commitment process.
RR717: clarify tariff and protocol language applying the “tank test” to day-ahead and RUC make-whole payments, explicitly excluding its use for multiday reliability assessments and local reliability events.
RR721: update SPP’s business practices to account for changes required by the RTO’s expansion in the West.
Oregon Public Utility Commission Chair Letha Tawney called for a less punitive data-sharing regime around wildfires, saying at FERC’s Wildfire Risk Mitigation Technical Conference that liability fears impede the industry from understanding the root causes of fires.
Speaking in the first wildfire panel Oct. 21, Tawney said “it is difficult to find consistent data about the different wildfires,” because wildfires are investigated by different federal and state agencies. This can impede the industry’s understanding of trends around ignitions and frequency of wildfires, according to Tawney. (See FERC Conference Speakers Emphasize Planning, Collaboration.)
Another challenge is data sharing on “near misses” — events that don’t escalate into wildfires but still trigger alerts. Those events are important to understand because they can identify issues that would not have been captured otherwise, such as equipment failures or issues with vegetation management, Tawney said.
“Not all states capture that, and it can be often confidential information,” Tawney said. “So, work around reporting would be helpful. But in many states, you have a liability regime … folks are very sensitive about cause codes and releasing information early. It can take a long time to investigate.”
“This is where I think moving toward a safety culture approach where we’re capturing near misses in a way that does not punish the actor, but allows us to capture root cause analysis, [makes sense],” she added.
The Nuclear Regulatory Commission and the aviation industry have these types of reporting regimes in place, Tawney said. The power industry must capture near misses and “spread the lessons back out similarly.”
“If we aren’t capturing those near misses, we don’t know if we’re doing better,” Tawney said. “We don’t know if … all the mitigations we’re deploying and the billions of dollars that we’re spending are really making our communities safer. We think they are. It’s an intuition, in many cases. So, finding ways to capture that data, protect the reporter from punishment outside of egregious behavior, I think, is really an important way that the sector needs to move forward to face the challenge.”
Tawney was joined on the panel by leaders from the federal government, the Western Electricity Coordinating Council and the South Texas Electric Cooperative (STEC).
Clif Lange, general manager at STEC and representing the National Rural Electric Utilities Cooperative, said capturing and sharing near-miss data “is incredibly important.”
Lange agreed with Tawney that people are hesitant to share data because of potential liabilities. He said the industry should create an environment “where people can freely share that information without … fear of retribution.”
“And I think as an industry, you’re able to advance and develop those mitigation programs more effectively and more efficiently and more quickly,” Lange said.
Standards
FERC hosted the wildfire conference in light of an executive order signed June 12 by President Donald Trump. The order calls for the federal government to work with state and local leaders to streamline “wildfire capabilities to improve their effectiveness and promoting commonsense, technology-enabled local strategies for land management and wildfire response and mitigation.”
The panelists also discussed safety standards around public safety power shutoffs (PSPS) and grid hardening.
Kristin Sleeper, deputy undersecretary for natural resources and the environment at the Department of Agriculture, said the agency is “looking forward to working with utilities and FERC on standards for power safety shutoffs.”
PSPSs are implemented differently across the country, Sleeper said. Wildfire used to be mainly a Western problem for five months out of the year. Now it affects the entire nation year-round, she said.
“We’re seeing fires in New Jersey, in different parts of the East,” Sleeper said. “So more uniform standards on how we can sort of prevent some of the ignitions from power lines.”
Sleeper added that the agency wants to “understand the utilities’ interest in hardening standards and grid resilience once a wildfire has burned through.” All too often, communities fail to improve resiliency when building back after a fire, and USDA wants to be “an active partner” in figuring out standards for hardening, Sleeper said.
Agency coordination is crucial, Lange said in agreement with Sleeper. However, he cautioned against implementing uniform standards.
Texas, for example, varies greatly just within the state, Lange noted.
“You’ve got the piney woods of East Texas that require a completely different set of practices than you would use to manage and mitigate fires as compared to the areas of West Texas, where you really have wide open lands, very little fuel out there to actually ignite.”
Power shutoffs should not be mandated, he added, noting that those can lead to “incredible hardships.”
“We need to make sure we’ve got a tool set but allow folks to be able to pull the right tool out of the toolbox when they need it, such that we get effective wildfire mitigation as a result,” Lange said.
New nuclear generation holds promise for the U.S. and its energy sector if its challenges can be overcome, panelists said during a Resources for the Future webinar.
The consensus was that regulatory, financial and policy support are important components of the process by which this can happen.
RFF President Billy Pizer opened the Oct. 21 conversation with John Williams, senior vice president of technical services at Southern Nuclear, which developed Plant Vogtle Units 3 and 4, the only U.S. nuclear construction project to reach commercial operation in decades.
With its delays and cost overruns, Vogtle illustrates the problems facing first-of-a-kind projects, Williams said, but also the benefits that can accrue for second-of-a-kind projects.
The project was plagued with unforeseeable problems such as the Fukushima disaster, the bankruptcy of its contractor and the COVID pandemic, Williams said, but there also were the predictable first-mover difficulties, particularly with Unit 3.
“We had challenges as we were building a new supply chain for a new technology,” he said. “And then workforce — it had been 30 years since we had built a new nuclear plant from scratch in the United States. So our workforce, we didn’t have that muscle memory that they have in other parts of the world, where they have been building on a more regular frequency.”
Unit 4 was in some ways a second mover, and the effect showed, Williams said: It cost nearly 20% less than Unit 3 to build, and commissioning took half as long.
How many more Vogtles would it take, Pizer asked, to reach that “Nth of a kind” balance where things can move fast and predictably, without cost overruns and delays?
Six to 10, Williams estimated.
The momentum has flagged, however. Heavy construction was completed at Vogtle in mid-2023, Williams said, and a workforce now experienced at building nuclear reactor complexes went its separate ways to build data centers and auto factories.
John Williams, Southern Nuclear | Resources for the Future
Williams said Vogtle 3 and 4 cost about $11,000 per kilowatt of nameplate capacity in present-day dollars, but if the next several projects were built in close succession around the same Westinghouse AP1000 reactor, the cost would gradually drop.
“By the time you come down that Nth of a kind curve, now you’re looking at $6,000 to $7,000 a kilowatt,” he said. “By taking a pause, we will absolutely have to do some relearning. The sooner we get started, the better off we’ll be.”
Karen Palmer, senior fellow in RFF’s electric power program, asked when all this nuclear generating capacity in the planning stages might start sending power onto the grid.
Matt Bowen, senior research scholar at Columbia University’s School of International and Public Affairs, ran through a partial list of the many development efforts vying for market leadership positions and said: “I sort of think the better question is, who if any of these entities is going to build something at an acceptable cost that can then be deployed a bunch of times in the 2030s and 2040s to make a sizable contribution to the U.S. energy portfolio, let’s say over 50 gigawatts.
Matt Bowen, Center on Global Energy Policy, Columbia University School of International and Public Affairs | Resources for the Future
“It’s a little too early to say how these are all going to turn out.”
Bowen said he is confident, however, that future gigawatt-scale projects could proceed with fewer delays and cost overruns than the two recent U.S. examples, Vogtle and the canceled V.C. Summer.
Alan Ahn, deputy director for nuclear at Third Way, said small modular reactors are promising because of their smaller footprint, which is expected to lower cost and increase versatility. Lower cost could facilitate financing , which has been a challenge for the nuclear industry.
“I think the reality in terms of hurdles going forward is that we’re still at a first-of-kind stage with these technologies. Matt went over some of those issues at length,” Ahn said. “There’s definitely light at the end of the tunnel. I think the challenge now is maximizing the potential of these technologies by building them at scale, maturing supply chain and reaching commercial maturity.”
Mixing into this crowded environment are a number of states promoting nuclear development, such as New York, whose governor has ordered the New York Power Authority to develop at least a gigawatt of nuclear capacity.
Alan Ahn, Third Way | Resources for the Future
Erich Scherer, director of strategy at the New York State Energy Research and Development Authority, said NYSERDA is not exactly new to the sector, having evolved from New York’s atomic agency.
But that was 50 years ago, and nuclear power has evolved greatly since then.
“So learning lessons is very much at the top of mind, both in terms of learning at the project level, but also in terms of learning from best practice, policy experience,” he said. “I’m also going to recognize that, I think, as a reality check, [there] just aren’t that many lessons to learn yet.”
Vogtle is a treasure trove of lessons, Scherer said, but it is an exception: Only a few of the many other reactor designs and business models being developed have even begun construction, and only a few states have put forth a comprehensive policy strategy.
New York is very aware of the risks involved in being a first- or second-mover, he said. “What’s really important in our mind is the possibility of cooperation between states, and so as we develop our master plan, we are also very much conscious that that’s not an effort in isolation. And New York state is part of initiative called the First Mover Initiative together with 10 other states.”
Erich Scherer, New York State Energy Research and Development Authority | Resources for the Future
This presents the chance to build a multistate order book and a pipeline that spreads the risks more broadly, Scherer said.
President Donald Trump, meanwhile, is roiling the regulatory environment in which all this would take place, demanding faster approvals and streamlined oversight.
Bowen said a lot of regulations are outdated and ripe for efficiency reviews, and there are opportunities to responsibly speed the process. But the Nuclear Regulatory Commission is being blamed unfairly for so few new reactors coming online in the past 30 years, he said.
Ahn addressed another challenge: the fuel supply chain. The U.S. gets its uranium from mines in other countries, he said, and while they can ramp up production, “I think the real challenge and bottleneck is with uranium conversion and enrichment, where producers need to invest in and execute expansions to their industrial capacity.
“In and of itself, that dependency on foreign fuel supply chains is not an insurmountable issue. We’ve operated our nuclear fleet on fuel converted and enriched overseas for very long time.”
The potential problem is that many other nations want to ramp up nuclear power generation, he said, setting up a strain on the supply chain, and that a significant share of the supply chain is still controlled by a potentially uncooperative country: Russia.
“I think particularly on nuclear fuel, there is need for coordinated, cooperative, international actions between the U.S. and its allies and partners,” Ahn said.
A relatively small project aiming to increase gas pipeline capacity into New England is raising larger underlying questions about how the region will balance gas reliability and affordability with longer-term efforts to transition away from natural gas.
Enbridge’s proposed expansion of its Algonquin pipeline, announced in September, has an estimated cost of $300 million and would increase the pipeline’s capacity into the region by about 2.5%. The company aims to complete the project in 2029.
Algonquin has announced it has reached agreements with seven utilities for the added capacity, including Rhode Island Energy and subsidiaries of Eversource Energy, which submitted a pair of 10-year supply delivery contracts associated with the project to the Massachusetts Department of Public Utilities in September.
Eversource said the contracts are needed to “address a reliability risk related to operational changes” instituted by Algonquin in 2019 reducing flexibility in nominations that previously allowed the company to nominate more than their contracted delivery entitlements in certain areas during cold-weather periods.
The company also said the added capacity would eliminate its “need to extend the G-Lateral supply portion” of its contracts with the Everett Marine Terminal (EMT), a major LNG import facility located north of Boston and owned by Constellation Energy.
By replacing LNG supply with pipeline gas, the project would reduce total gas costs for customers of two subsidiaries by about 5% and 1%, the company said.
“Without the proposed agreement, [Eversource] and its customers risk exposure to inadequate and unreliable supply and high city-gate pricing during peak days for customers served by Algonquin’s G-System, and would need [to] enter into negotiations with Constellation … for gas supplies to serve the G-Lateral from EMT after 2030,” Eversource argued.
However, environmental nonprofits argue the Algonquin expansion project would not eliminate the region’s overall need for the Everett terminal and instead likely would shift its costs to other customers.
In Eversource’s filing, the company appears to acknowledge the Algonquin expansion would not eliminate the region’s reliance on Everett, writing that the agreement would “not resolve regional dependence on natural gas from peaking resources” and adding that the terminal “provides a unique and critical energy resource in New England.”
In joint comments submitted earlier in October, the Acadia Center and the Conservation Law Foundation (CLF) wrote that the DPU must consider how the contracts “will impact not only Eversource customers, but also other gas customers, including National Grid and Unitil, whose contracts with Constellation mirror [Eversource’s].”
The Role of Everett
Until spring 2024, Everett’s main customer was Mystic Generating Station, a 1,413-MW, Constellation-owned combined cycle plant located nearby.
In the months leading up to Mystic’s retirement, local distribution companies owned by National Grid, Eversource and Unitil reached agreements with Constellation to keep Everett open through 2030. The contracts were necessary to provide adequate supply and preserve system reliability, the utilities wrote (DPU 24-25-B, et al.). (See Massachusetts DPU Approves Everett LNG Contracts.)
Everett “is ideally located in the heart of the market” at the back end of the Tennessee and Algonquin pipelines, Richard Levitan, president of the energy consulting firm Levitan & Associates, explained in an interview with RTO Insider.
Levitan stressed the importance of local deliverability to the system. LNG from Everett and Repsol’s Saint John LNG terminal in New Brunswick provides the “oomph to energize the network of pipelines serving gas utilities and generators in New England during cold snaps or some type of outage contingency along the mainlines serving New England,” he said.
He added that Everett “is the primary hub of truck-transported LNG to refill the dozens of satellite LNG tanks in New England that bolster pressure behind the pipeline citygates,” a role that cannot be replicated by the Saint John terminal.
Levitan noted that the Algonquin expansion project “is small in relation to the daily output” of both the Everett and Saint John facilities when the terminals are performing. He emphasized that, unlike conventional forward-haul service from the Gulf Coast or Marcellus Shale, LNG facilities provide operational and scheduling flexibility by enabling injections into the back end of the gas systems.
“When these import facilities are dispatching during cold weather events, it’s beneficial to the bulk electric generation market, and also to the LDCs, who generally look to supplement their pressures via displacement services when there are harsh operating conditions,” he said.
While utilities and gas generators rely on Everett to add supply downstream of New England’s gas constraint during peak periods and to provide backup supply during pipeline outages, the facility again faces an uncertain future after its contracts with the utilities expire in 2030.
The contracts are costly for ratepayers; Eversource estimated in 2024 they would increase rates by 5 to 7% for customers of one subsidiary and 2 to 3% for customers of another. Long-term reliance on Everett also likely would run contrary to Massachusetts’ longer-term efforts to move away from natural gas to reach net-zero emissions by 2050.
When approving the contracts, the DPU required the gas companies to “make significant strides to reduce or eliminate their reliance on EMT in the near-term” and directed them to “fully investigate all possible alternatives to EMT … including energy efficiency, strategic electrification and networked geothermal projects and, to the extent feasible, to coordinate their planning efforts.”
The order also required annual reports about the utilities’ efforts to reduce reliance on the facility, and in fall 2024, the Massachusetts Office of Energy Transformation established a working group focused on moving away from Everett.
Who Pays?
While the pace and trajectory of the gas transition in Massachusetts likely will determine the long-term demand for existing and new gas infrastructure, the fate of Everett, as well as the fate of gas pipeline expansion projects into the region, may be defined in large part by questions about funding.
The Algonquin expansion project essentially is a significantly scaled back version of Enbridge’s previously introduced “Project Maple,” which proposed to increase Algonquin’s capacity by up to 250,000 Dth/d at the eastern end of the pipeline. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
The smaller size of the updated 75,000 Dth/d expansion project appears to reflect the challenges of finding long-term customers for the increased capacity.
“Following the conclusion of the Project Maple open season in November of 2023, we decided to right-size Project Maple to better meet our customers’ specific needs, with a smart, targeted enhancement,” Enbridge spokesperson Melissa Sherburne said in a statement.
While New England relies heavily on gas generation, which hit a record high in 2024, generators’ access to gas is constrained during cold weather when heating demand is high. (See New England Gas Generation Hit a Record High in 2024.) Generators historically have been reluctant to take on long-term gas contracts, largely because of the financial risks associated with assuming these commitments.
Electric ratepayers also appear unlikely to finance new infrastructure; a 2016 ruling by the Massachusetts Supreme Judicial Court prohibits charging electric customers for the costs of new pipelines.
Meanwhile, residential, commercial and industrial gas demand has been relatively stagnant in recent years, and, seeking to decarbonize, Massachusetts lawmakers and regulators have taken significant steps to slow the expansion of the system and push gas customers to electrify. (See Outgoing Mass. DPU Chair Van Nostrand Discusses Gas Transition.)
“As far as who would pay [for Everett] in 2030 if Eversource is not a contracted party, it would have to be other LDCs, conceivably generators if we see the evolution of price signals under accreditation taking form, and marketers,” Levitan said.
As ISO-NE overhauls how it accredits resources in the capacity market, the RTO is poised to increase incentives for resources to procure firm fuel. However, the extent to which this will cause generators to enter long-term firm contracts is unclear.
In ISO-NE’s Capacity Auction Reform project to date, “we’re not seeing the evolution of accreditation principles that will clearly induce the generators to line up firm rights, so I don’t think at this moment in time we can reasonably expect the generators as a cohort group in New England to foot the bill for a major new pipeline push,” Levitan said.
Everett’s funding challenges mirror the challenges faced by any large pipeline project into the region, which are complicated by the state’s push to decarbonize.
Interstate pipelines serving eastern New York (2022) | S&P Global
Climate and consumer advocates have argued that Massachusetts must be careful not to make long-term investments in the gas system that end up becoming stranded assets. Some advocates see the 10-year duration of Eversource’s proposed Algonquin expansion contracts as reflecting uncertainty about long-term gas demand on the distribution system.
Joe LaRusso, senior advocate at the Acadia Center, said he’s skeptical gas utilities will experience enough new demand to support a “a substantial increase in gas capacity into the region.” He added that pipeline companies looking to build major new projects “can’t find the off-takers for this stuff; they can’t get it built.”
Acadia and CLF’s comments on Eversource’s contracts with Enbridge focus on Eversource’s underlying assumptions about its forecasted gas demand between 2029 and 2039. The groups highlight data from the U.S. Energy Information Administration indicating that overall residential, commercial and industrial gas demand in Massachusetts declined between 2019 and 2024.
They wrote that Eversource has provided “no basis to determine what their gas requirement will be over the term of the proposed contracts,” nor data on how “declines in statewide gas consumption in those sectors might ultimately influence either their overall consumption or their design day supply.”
In Eversource’s initial petition, the company wrote it “has not identified other viable alternatives to the proposed agreement,” adding that “the pace, scale and scope of energy efficiency and electrification would be insufficient to address the load requirements for the G-Lateral.”
Decarbonization Challenges
As utilities and regulators work to ensure the reliability of the state’s gas system, an inherent tension exists between investments to bolster the system and efforts to decarbonize.
While the gas industry frequently points to the reduction in carbon dioxide emissions associated with burning natural gas instead of coal or oil, methane is a key driver of manmade climate change and has particularly severe warming effects when evaluated over a more immediate time frame.
In a landmark order in late 2023, the DPU ruled that the decarbonization of the state’s gas system should center around electrification and emphasized the need for a managed transition away from gas and gas infrastructure (DPU 20-80-B). (See Massachusetts Moves to Limit New Gas Infrastructure.)
The state remains in the early stages of implementing this new regulatory framework, and in recent months, utilities and climate advocates have clashed over the LDCs’ legal obligation to serve customers, and whether the utilities could require customers to give up their gas service when decommissioning a section of pipe.
If successful, the electrification push would drive a substantial increase in power demand, which could cause continued growth or reliance on gas generation. While there is almost no proposed new gas generation in the ISO-NE queue, the challenges experienced in the offshore wind industry create significant questions about how the region will meet this growing demand.
“The demise, temporary or not, of offshore wind bodes poorly for certain environmental goals to be achieved in the early and mid-2030s if electrification gets the kind of traction that regional policymakers envision,” Levitan said. “There could be much more work burden on the existing thermal fleet to accommodate a pathway that is all about switching over from a summer to winter peak because of electrification.”
But for grassroots climate activists in Massachusetts, any efforts to expand natural gas infrastructure into the state are a step in the wrong direction.
“The answer is not, and never has been, keeping on with the gas system,” said Cathy Kristofferson, a longtime environmental activist in the state who co-founded the Massachusetts Pipe Line Awareness Network. “Everyone’s trying to figure out the affordability angle of it all, and for us, adding a bunch more steel in the ground is never affordable.”
Rosemary Wessel, an activist with the Berkshire Environmental Action Team, said Enbridge’s recent Algonquin proposal appears to be part of a strategy focused on incremental expansions to increase gas capacity into the region.
At an industry conference in September, Mike Dirrane, director of Northeast marketing at Enbridge, speculated that there may be an additional project after the current Algonquin expansion effort “to meet additional needs further down the road.” (See Gas Industry Sees Political Opportunity in New England.)
“They’re segmenting a larger expansion into small projects,” Wessel said. “We should not be serving that by approving contracts for more gas.”
Following a recent announcement that it plans to withdraw from the Western Resource Adequacy Program, NV Energy said it is discussing a potential new resource adequacy program with other participants in CAISO’s Extended Day-Ahead Market.
Speaking during an Oct. 21 prehearing conference before the Public Utilities Commission of Nevada, Lindsey Schlekeway, market policy director for NV Energy, described the program as “a high-level concept” and said there are no formal agreements yet.
The conference was regarding NV Energy’s energy supply plan update for 2026/27. Tim Clausen, NV Energy’s vice president of regulatory affairs, said the company would file a request with the PUCN to join the EDAM as an amendment to the company’s energy supply plan.
As part of an update on the supply plan, Schlekeway filed written testimony explaining the company’s decision to withdraw from Western Power Pool’s WRAP. She detailed five “critical issues,” including “steep penalties for capacity deficiencies identified seven months before the compliance season.” (See NV Energy to Withdraw from WRAP.)
Another issue is that all load-serving entities in Markets+ will be required to participate in WRAP.
“While expanding participation can enhance regional reliability, it may disadvantage entities that prefer to remain in the Western Energy Imbalance Market … or transition to the Extended Day-Ahead Market,” she wrote.
In contrast to Markets+, EDAM won’t require its participants to belong to an organized resource adequacy program. Instead, EDAM will use a resource sufficiency evaluation to ensure participants’ RA going into the day-ahead and real-time time frames to meet their own needs without depending on others.
NV Energy will continue to watch WRAP’s development and remain open to future participation if the five issues are addressed, Schlekeway said.
“We will continue to follow WRAP, but we will also follow other avenues if others want to discuss resource adequacy in other forums in the West,” Schlekeway told Commissioner Tammy Cordova, the hearing officer in the case.
Schlekeway said that even after submitting a withdrawal letter, NV Energy can remain active in WRAP through participation in WPP’s Resource Adequacy Participant Committee, for example.
Cordova asked what would happen if the PUC directed NV Energy to participate in WRAP. “We can always re-enter the program,” Schlekeway responded.
Contacted after the prehearing conference, Schlekeway referred further questions on a potential Western RA program to an NV Energy spokesperson, who said the company had no further comment.
Rebecca Sexton, chief strategy officer for WPP, told RTO Insider that the organization is “aware of discussions about creating an alternative resource adequacy program.”
Sexton hopes that any entities that choose to leave WRAP will stay involved with the program’s governance during the two-year exit window and later decide to commit to binding participation. With binding-phase commitments from 11 participants and the potential for others to join, she said WRAP will launch “with a significant footprint with substantial load and resources and geographic diversity.”
Critical Time for WRAP
The discussion of an alternative resource adequacy program comes at a critical time for WRAP.
An Oct. 31 deadline is looming for participants to commit to the program’s first binding phase in winter 2027/28. Of the 11 members that have so far committed to WRAP’s first binding season, all but one are expected to join Markets+.
But some members say they need more time. PacifiCorp has asked WPP’s board of directors to allow WRAP participants to defer their decision to commit to the program’s binding phase by at least one year. (See PacifiCorp Asks WPP to Delay WRAP ‘Binding’ Phase Commitment Date.)
Portland General Electric also sent WPP a letter seeking a one-year deferral of the binding season. PacifiCorp and PGE have signed implementation agreements with CAISO to become EDAM’s first participants in 2026.
In response letters to PacifiCorp and PGE, WPP Board Chair Bill Drummond said delaying the binding phase “would have a detrimental effect on reliability for the region, including undermining confidence in WRAP data and modeling, limiting program compliance and preventing us from unlocking the full benefits of the program.”
The Imperial Irrigation District, which is slated to join EDAM in fall 2028, has staff participating in discussions of a potential new Western RA program.
“Momentum has started, communication is active, and kickoff meetings have begun,” IID spokesperson Robert Schettler told RTO Insider.
The district wants to be fully aware of, and ready to use, the full menu of RA options, said Schettler, who noted that IID is a balancing authority that is a net exporter most of the year.
IID isn’t currently pursuing WRAP membership, although it is an option in the future, he said.
When contacted by RTO Insider, a PacifiCorp spokesperson did not directly answer a question about whether the company has been participating in discussions of a new RA program.
“As part of prudent utility operations, PacifiCorp routinely evaluates opportunities to benefit customers, and resource adequacy is a significant focus of that process,” the spokesperson said in an email.
PacifiCorp is considering its participation in the WRAP binding phase ahead of the Oct. 31 deadline, the spokesperson said, and plans to continue its involvement in the program regardless of the decision.
