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April 18, 2025

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CAISO Issues ‘Expedited’ Plan for Allocating EDAM Congestion Revenues

CAISO on April 17 released a draft final proposal detailing how its Extended Day-Ahead Market (EDAM) will allocate congestion revenues in circumstances when a transmission constraint in one balancing authority area produces “parallel” flows — with resulting transmission congestion — in a neighboring BAA also participating in the market. 

The draft proposal is the product of an “expedited” stakeholder process the ISO kicked off in March to address concerns among some Western electricity market participants that EDAM would leave some non-CAISO participants exposed to congestion charges for constraints occurring outside their systems, while not providing them the ability to adequately recover or hedge against the charges. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.) 

“This proposal for parallel flow congestion revenue allocation is an initial step toward continued evolution of the overall congestion revenue allocation design informed by market operational experience and stakeholder input,” CAISO said in the proposal. 

Vancouver, Canada-based electricity trader Powerex first called attention to the issue in a February paper contending that EDAM’s handling of congestion revenues represented a “design flaw,” which the company identified after reviewing PacifiCorp’s proposed revisions to its open access transmission tariff intended to accommodate its participation in the market, scheduled to begin in 2026. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

Powerex is a firm OATT rights holder in PacifiCorp’s system, and it argued that any such transmission customer stands to lose value in its contracts under the arrangement. 

Seeking Balance

CAISO said its draft proposal seeks to strike a balance between EDAM’s existing FERC-approved rules related to congestion revenues and the alternative scheme it floated in the issue paper kicking off its expedited stakeholder initiative. 

Under EDAM’s existing rules, congestion revenues are allocated to the BAA containing a constraint, with the operator of that BAA allowed to sub-allocate any revenue it receives from the ISO to transmission customers according to the procedure outlined in that BAA’s OATT. 

“This congestion allocation method recognizes that the balancing area where the internal transmission constraint is located bears the effects of that congestion and the reliability impacts associated with the constraint, and thus congestion revenues accruing across the interconnected EDAM footprint associated are allocated fully to the EDAM balancing area where the constraint is located,” CAISO notes in its proposal. 

The ISO said many stakeholders “saw merit” in the existing design but “also recognized the concerns expressed with parallel flow congestion revenue allocation” and the need to develop a new “transitional” approach for allocating revenues “to support the ability to more readily protect or manage congestion cost exposure for OATT transmission rights holders.” 

But stakeholders also expressed concerns about the potential alternative outlined in the issue paper, which proposed to allocate congestion revenues only to the BAA in which the revenues accrued, not to the neighboring area where the constraint was located. Some commenters thought the alternative went too far in reallocating the revenues, while others worried the approach could increase incentives for some transmission users to self-schedule generation to gain a more complete hedge, which would reduce the efficiency of market operations. 

CAISO said its proposed design instead “leverages elements of the transitional alternative introduced in the issue paper and retains aspects of the current, FERC-approved, design to congestion revenue allocation; i.e., it is incremental to the underlying congestion revenue allocation methodology.” 

Under the draft final proposal, parallel flow congestion revenues collected in an EDAM BAA that result from a binding constraint in a neighboring area will first be allocated to the BAA in which the overflow congestion occurs — and the revenues are collected. That will enable that BAA to distribute funds to firm OATT transmission rights holders who possess long-term and monthly point-to-point (PTP) and network integration transmission service (NITS) rights and have submitted “day-ahead balanced source/sink schedules.” 

“Consistent with the existing EDAM design, transmission customers will register their firm PTP and NITS transmission rights, with the market operator identifying the nature of the rights from source to sink. These registered transmission rights will be associated with a contract reference number, which, when included in the bid submission, associates that bid with existing OATT transmission rights,” the proposal states. 

The plan also stipulates that any remaining congestion revenues associated with the parallel flows would be allocated to the EDAM BAA in which the constraint occurred. 

“This aspect of the design mitigates the concerns expressed by stakeholders that, under the transitional alternative described in the issue paper, balancing areas may be exposed to congestion costs (negative congestion revenues) associated with parallel flow effects when generation in the balancing area provides counter flow benefit to the direction of the transmission constraint located in a neighboring balancing area,” according to the proposal. 

Additionally, EDAM would continue to allocate any congestion revenues that accrue within the BAA containing the constraint to that BAA, “consistent with the FERC-approved EDAM framework.” 

Acknowledging “the complexity of the overall topic of congestion revenue accrual and allocation,” the proposal provides multiple illustrated examples of how the plan would work in practice. 

‘Guns Blazing’

CAISO is moving quickly to wrap up the congestion revenue allocation proposal in time for a vote next month by its Board of Governors and the Western Energy Markets (WEM) Governing Body. 

WEM stakeholders appear to largely on board with the ISO’s sense of urgency. 

During an April 9 meeting of the WEM Regional Issues Forum (RIF) in Portland, Ore., representatives from most RIF sectors cited congestion revenue allocation as CAISO’s top priority right now, at the forefront of other issues the ISO will need to address to ensure a smooth launch of EDAM in 2026. 

“We support moving quickly in the congestion revenue allocation initiative,” Vijay Singh, senior organized markets analyst at PacifiCorp, said on behalf of the RIF’s EDAM sector. PacifiCorp will be the first utility to begin participating in the EDAM next spring. 

“We were really ready to come in guns blazing and go after the ISO for not doing more on congestion, but we really got to commend the ISO for kicking off the process and looking to go to the Board of Governors by May,” Avangrid’s Scott Olson said for the Independent Power Producers and Marketers sector. 

The Bonneville Power Administration’s Allie Mace, RIF liaison for the Power Marketing Administration sector, also commended CAISO for moving on the issue, but she noted the “transitional” nature of the proposed solution and encouraged the ISO to include an initiative for longer-term solutions in its policy initiative road map. 

CAISO will hold a stakeholder meeting to discuss the draft final proposal April 23. 

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ISO-NE Prepares Expedited Filing After Ruling on Order 2023 Compliance

The NEPOOL Transmission and Markets Committees voted April 17 to support an ISO-NE proposal to adjust several key dates and deadlines in its compliance proposal for FERC Order 2023, which the commission approved April 4. The committees also voted to support an amendment by RENEW Northeast to extend the deadline for late-stage projects to complete their system impact studies (SISs).

FERC’s ruling accepting ISO-NE’s Order 2023 compliance filing did not alter the RTO’s proposed timeline for its transition process, which includes dates and deadlines that have passed and no longer are viable. (See FERC Approves ISO-NE Order 2023 Interconnection Proposal.) To amend these issues, ISO-NE plans to file “narrowly tailored tariff revisions to only adjust transition related dates in the compliance proposal by approximately one year.”

These changes would allow the RTO to align its transitional capacity network resource (CNR) group study with the 2025 Interim Reconfiguration Auction Qualification Process — a necessary step to run the CNR study in 2025 — and start the transitional cluster study (TCS) in October.

The transitional CNR study is intended to enable interconnection customers with complete SISs to achieve capacity interconnection rights, while the TCS will be open to all other projects with valid interconnection requests. ISO-NE will use the results of the CNR study as an input to the TCS.

The RTO plans to make a Section 205 filing with the timeline changes “immediately following the May 2025 Participants Committee meeting, and request a next day effective date for the revisions to adjust the dates,” said Alex Rost, director of transmission services at ISO-NE.

Rost said ISO-NE has closed the queue again after opening it briefly on April 1 and noted that only resources with valid interconnection requests as of June 13, 2024, will be eligible to enter the TCS. The next opportunity for resources to enter the interconnection queue will be the initial cluster request window, which will open after ISO-NE completes the TCS. If the TCS begins in October 2025, the queue would be slated to reopen in late 2026.

Because the new interconnection rules already are in place — and technically took effect Aug. 12, 2024, despite FERC not ruling until April 4, 2025 — ISO-NE has stopped work on all ongoing interconnection studies under the prior rules, Rost said. He noted that “any on-hand deposits associated with an [interconnection request] that is eligible for the transition can be applied to transition studies.”

He said ISO-NE will honor any SISs completed between the official effective date and the date ISO-NE received the ruling, as these studies were completed under the rules that were in place at the time.

Abigail Krich of Boreas Renewables, speaking on behalf of RENEW Northeast, proposed to amend the expedited filing to allow late-stage requests to continue their SISs until Aug. 29, 2025.

“The only component of the ISO’s originally proposed transition that they do not propose to shift forward by [about] one year is the late-stage SIS completion deadline,” Krich wrote in a memo prior to the meeting. She noted that ISO-NE initially proposed to continue working on late-stage SISs through Aug. 30, 2024.

Krich said late-stage projects already could have spent “on the order of $250,000” on interconnection studies, which would be invalidated if the studies are not completed prior to the TCS. She said there appears to be 10 or fewer projects that could be eligible for this late-stage treatment.

“These [interconnection requests] remain eligible to enter the TCS this fall, but doing so will cost them more money, delay their interconnection and put them at risk of larger withdrawal penalties,” Krich said. She added that completing the system impact studies for as many projects as possible prior to the TCS would reduce the size, complexity and withdrawal risks of the study.

“Continuing work on the few interconnection requests that would potentially be identified as ‘late-stage’ would be a relatively small amount of work for the ISO’s interconnection team and should not take away from the ability to implement the remainder of the Order 2023 transition,” Krich added.

Developers with late-stage interconnection requests have expressed a strong interest in continuing their studies and argued it is in the region’s best interest to complete these studies to help bring new resources online as quickly as possible.

ISO-NE expressed concern about potential issues associated with reintroducing the old interconnection rules for late-stage requests, and that incorporating RENEW’s proposal into its filing could complicate the approval of its proposed timing changes.

The committee voted to support both RENEW’s amendment and ISO-NE’s proposal without the amendment. ISO-NE said it will consider its options before bringing the proposal to the NEPOOL Participants Committee on May 1.

ISO-NE also plans to work with stakeholders to make a second filing to address the series of relatively minor issues that FERC identified with its Order 2023 compliance proposal. This filing is due in early June.

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NJ Gov. Urges FERC to Investigate PJM; Christie and Phillips Defend PJM

New Jersey Gov. Phil Murphy (D) is asking FERC to investigate “potential market manipulations” in the PJM Base Residual Auction (BRA) in July 2024 that state officials say contributed to a 20% hike in electricity rates in New Jersey. 

Murphy, in a letter to FERC commissioners, said he had “deep concerns about the PJM cost crisis.” He said he believes the “exorbitant price increases” in PJM’s July auction “may have been subject to market manipulation.” 

FERC Chairman Mark Christie defended PJM staff in comments at the monthly FERC meeting April 17. 

“A lot of this criticism that I’ve been seeing in the media, directed at PJM and its management, and blaming them for everything that is wrong with the PJM capacity market, is in many ways misplaced,” he said. “And a lot of it is because of state policies that have sort of come to a head just recently.” 

Christie particularly cited the work of outgoing PJM CEO Manu Asthana and other PJM executives. (See PJM CEO Manu Asthana Announces Year-end Resignation.)  

“Manu had the unlucky job of coming in when a lot of factors that were put in play 20 years ago sort of started to come to a head,” Christie said. “These factors, such as the big increase in load that we’ve been seeing in the last few years, the loss of resources has been ongoing for years, and all this sort of came to a head. But he has done, I think, an outstanding job. I’ve always found him to be very, very straightforward and open in dealing with me.” 

Commissioner Willie Phillips agreed with Christie. “I want to echo the comments you made about Manu and PJM leadership. I think what you said was spot on and very well said.” 

Asked whether FERC would launch an investigation, Christie said he had to be careful about commenting because the commission has pending cases dealing with the high prices from the last capacity auction. But he noted he has been a skeptic/critic of the capacity market construct since it first was launched. 

“I think that a lot of the problems that PJM is facing today are the result of trends that have been going on for 21 years,” Christie said. “And again, I’m a fact-witness to that. I’ve been there, and I think a lot of decisions were made years ago that are now showing up and causing problems for a lot of the states that are complaining the most. One of the biggest problems, I think, was 20 some years ago. They made a decision to use the PJM capacity market as their mandatory sole source of resource advocacy, and so that put them at the mercy of the PJM capacity market.” 

Many of the member states have pointed the finger solely at PJM for those problems, but Christie argued some of their state policies are to blame as well. FERC is holding a two-day technical conference in June to look at resource adequacy, where the issues will be discussed. 

Gov. Murphy’s letter urged FERC to “determine the extent to which any such manipulation may have resulted in higher capacity auction prices that are being passed on to retail electricity customers in the PJM market, particularly in New Jersey.”  

“I believe that billions of dollars in excessive costs for [consumers] are the direct result of fundamental flaws in PJM’s capacity market and were foreseeable and preventable,” the letter said. 

In response, PJM released a statement that said the organization “has not seen evidence that supports a finding of market manipulation in the 2025/26 capacity auction, but we take such allegations very seriously.” FERC’s Office of Enforcement “is the right place to address such a concern, and PJM will follow any directives we receive from FERC,” the statement said. 

“New Jersey has insufficient generation in-state to meet its needs, and has to make up this difference through imports,” said the statement, released by spokesman Jeffrey Shields. “A seven-year-long effort by New Jersey to fill this gap with offshore wind has failed to deliver any results whatsoever, and consumers are now paying the price for this failure.” 

Murphy’s statement marks a new stage in the friction between PJM and New Jersey and other states over the rapidly increasing cost of electricity and the region’s ability to generate enough power in the future. 

New Jersey and Maryland officials on April 16 attended a press conference for the release of a report by Evergreen Collaborative, a national environmental group that promotes solutions to climate change. The report predicted a 60% hike in electricity rates unless PJM takes steps to reform the process by which new clean energy sources are added. (See NJ, Md. Officials Target PJM After Critical Report.)  

Pennsylvania in January filed a complaint with FERC about PJM, which resulted in the RTO’s agreement to cap future auctions’ capacity prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.) 

New Jersey’s draft master plan, released March 13, predicts demand for electricity will increase by 66% by 2050, and state officials are concerned about how they will meet that need. (See NJ Releases Electrification-focused Energy Master Plan.) 

PJM says the expected shortfall in power is in part due to the slow pace of new energy sources coming online compared to the far faster pace at which older generating sources — mainly fossil-fueled sources — are going offline, often in line with state policies. In addition, PJM says the region can expect an influx of high-energy-using entities, especially artificial intelligence data centers. 

New Jersey, and other states, say PJM has failed to plan for the surge and the problem is exacerbated by the slow pace at which the agency approves new energy sources, especially renewable energy sources. 

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Data Centers’ Reliability Impacts Examined at FERC Meeting

Sudden trips offline by data centers in Virginia and cryptominers in ERCOT present new reliability challenges that must be managed, NERC Chief Engineer Mark Lauby told FERC at its monthly open meeting April 17.

The grid in Loudoun County, Va., home to the largest concentration of data centers in the world, was experiencing some voltage sensitivities last summer, Lauby testified.

“In July 2024 we saw about a 1,500-MW drop as a result of some system conditions — in this case, switching after a fault on the system,” Lauby said. “And within 50 seconds, three of those voltage excursions occurred, and the load is monitoring that, and when it sees that happen, it comes offline because it wants to protect its cooling load.”

NERC released a report on the incident in January that details the grid conditions before and after the data center load went offline. (See NERC Report Highlights Data Center Load Loss Issues.)

A similar event happened in Loudoun and neighboring Fairfax County, where 1,800 MW of load suddenly dropped off the system. Lauby said while that is still being investigated, he suspects it will be similar to the July 2024 incident.

Texas has seen more frequent but smaller events as grid conditions have caused cryptocurrency mining facilities to trip offline 25 times between November 2023 and this January, leading to 100 to 400 MW of losses in each incident.

“Historically, if we lose generators, it can trip off the grid,” FERC Chair Mark Christie said during the meeting. “Now we’ve got another issue, which is if large load users simultaneously go off together, it affects the frequency and potentially trips off the whole system.”

The grid can be engineered to avoid those cascading outages across multiple data centers to avoid a situation where the grid’s largest single contingency comes from demand (as opposed to a large power plant or transmission line), Lauby said.

“That comes down to engineering, modeling and continuing to work with the industry — in this case, the large load industry and the power industry — to see how we manage that interconnection,” he added.

NERC is considering rule changes to deal with the newfound risk, which is going to be exacerbated as individual data centers’ load grows to the size of major cities. The grid has dealt with large industrial facilities at 100 to 200 MW for decades, but some of the proposals for large data centers run to thousands of megawatts, which compares to the total loads of San Francisco or D.C. in a single place, Lauby told FERC.

“We need to, obviously, make sure that’s managed well, and the engineering is done to ensure that we minimize the chances for things to happen,” he added.

NERC stood up a Large Loads Task Force in 2024 that is expected to issue papers and guidelines to address the risks associated with the issue. The ERO is also working on industry guidance on large loads, incorporating work from the task force.

Part of that analysis is to determine how to register the loads, either by requiring the customers themselves to register with NERC, or if that is not legally feasible, then getting their load-serving entities to do it for them, Lauby said. Then once the facilities are registered, NERC will craft reliability standards so that the chances of such incidents are minimized.

“Large numbers actually really scare me; the potential reliability impact of these drops sound pretty severe,” Commissioner Judy Chang said.

Modeling can help NERC secure the grid against uncontrollable outages of data centers; Chang asked what kind of data are needed to effectuate that.

Losing 1,500 MW of load is akin to one and a half large nuclear units tripping offline, but the grid has reserves that can maintain reliability in such cases, Lauby replied. NERC has the authority to get data from the industry under the Federal Power Act.

“For the loads, they’ve just been good enough to work with us,” Lauby said. “And, so, is that going to be good for the long term? Probably not … [it’s] something we need to think about.”

Large loads tripping offline is one part of the reliability equation when it comes to data centers, with the other key part being meeting their demand with an adequate supply of resources, Lauby said.

“The definition of reliability is adequacy and operation reliability,” he said. “So, we’ve got both problems.”

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CAISO Pauses Study of New Market Run Proposal for Gas Resources

CAISO on April 16 sidelined a proposal to provide an additional market run for gas resources due to a lack of information on the subject and a need for operational experience with the ISO’s Extended Day-Ahead Market (EDAM).  

The proposed new market run, known as D+1.5, would occur between CAISO’s two-day-ahead market run, D+2, and day-ahead market run. D+1.5 would provide a better estimate of next-day markets as a potential to reduce reliability concerns, said NV Energy, a stakeholder in CAISO’s Gas Resource Management Working Group. 

Currently, CAISO uses two two-day-ahead market processes: D+2 and the residual unit commitment (RUC) look-ahead advisory. Stakeholders raised concerns about the RUC’s timing and forecasting accuracy and said there is a general “lack of confidence” using such information to inform fuel procurement decisions, per CAISO’s latest issue paper on the subject, published in January. 

D+1.5 could provide new information to participants that was not available in time for the D+2 but becomes available and accessible to CAISO. For example, scheduling coordinators could submit new or updated bids, informed by the next-day gas day trading activity, into the day-ahead market to inform the D+1.5, the paper says. 

However, to provide a D+1.5 market run, CAISO would need to establish a new process to collect gas trading data and run new forecasts. If not, D+1.5 would use the same forecasting information already used by the market processes on the trade day. Adding new forecasting services would increase vendor and personnel costs to monitor and maintain the new forecasting suite, the paper says.  

The “highest-priority scope item” for CAISO’s Gas Resource Management Working Group is to provide more market information to participants prior to the day-ahead market to support fuel procurement, the paper says. But the value of a new market run “must be weighed against the cost of gathering new information, running the optimization and validating a new stream of market results made available to market participants,” the paper says. 

“While we support the continued consideration of this new market run, we think it should be after we complete an assessment of D+2 and have some operational experience with EDAM and the new D+2 market run,” Sylvie Spewak, CAISO senior policy developer, said at the April 16 working group meeting. “At this time, we don’t intend on including the D+1.5 proposal in this upcoming straw proposal in detail. Let us know if you disagree with this approach.” 

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FERC Upholds Preliminary Permit for Pumped Hydro Concept

FERC has upheld the fourth preliminary permit (P-15332) granted in three decades for a pumped hydro concept in southeastern Pennsylvania. 

FERC in November 2024 granted a 48-month preliminary permit to York Energy Storage LLC for an 858-MW facility along the Susquehanna River near Lancaster and York that could produce 1.5 million MWh per year. 

Environmental advocates, local governments and other interested parties protested and requested a rehearing. 

FERC’s April 17 order shot down the various arguments they submitted with their request. 

The ruling states that concerns raised about the potential impact of the YES project — should it be built — are speculative and premature; one of the purposes of a preliminary permit is to give the permittee a chance to determine the potential impacts and design the project to avoid or mitigate them. 

Issuance of a preliminary permit also does not require a finding of public interest or a balancing of interests, FERC wrote; licensing, construction and operation of the YES project might cause environmental and other impacts, but preliminary licensing would not. 

FERC also rejected the contention that it should have found YES unfit for a preliminary permit for reasons including that it is a paper entity, has not demonstrated how it will fund its activities and has a history of noncompliance. FERC wrote that its past practice does not dictate a financial review for a preliminary permit, and that YES has no history of serious violations of hydropower licenses. 

Finally, FERC rejected the argument that it had violated the Federal Power Act by granting multiple preliminary permits for the same project, three of them to entities with a common principal. 

FERC issued two to Mid-Atlantic Energy Engineers LTD in the 1990s and one to Cuffs Run Pumped Storage LLC in 2011. But FERC said in its April 17 order that even if it treated Mid-Atlantic as the same entity as YES, more than 20 years separated the permits, so it is reasonable to treat the YES request as a new application rather than a successive application. 

The issues raised in the rehearing request are speculative, the order reads.  

It concludes: “We continue to find that it is in the public interest to consider such impacts at the licensing stage, when such impacts are more defined, after York Energy has completed preliminary study, thereby resulting in a more accurate and complete record, and that declining to issue a preliminary permit based on speculative impacts or incomplete impacts is not appropriate at this stage of potential development.” 

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NYISO Cancels 2033 Reliability Need for NYC

NYISO ended the Operating Committee’s meeting April 17 with a surprise announcement: The ISO is no longer concerned about a violation of reliability criteria in New York City in 2033 and has canceled its search for a solution.

Zack Smith, senior vice president of system and resource planning, told the committee that updates to assumptions used in demand forecasting and demographic trends had eliminated the need over the 10-year horizon. Margins are still shrinking because of plant retirements, he said, but not enough to trigger the reliability need.

NYISO had officially made the declaration in November 2024 as part of its 2024 Reliability Needs Assessment. It triggered a process in which the ISO solicits solutions, including transmission-based from the local transmission owners, and generation and demand response from market participants. (See NYISO Publishes Final RNA Showing Reliability Need for NYC.)

Kevin Lang, a partner with Couch White who represents the city at the ISO, asked if the forecast included the completion of Empire Wind 1, an offshore wind project that just the day before was ordered to halt construction by the Trump administration. (See Feds Move to Halt Construction of Empire Wind 1.)

Smith affirmed that it was and that NYISO was confident that even a “significant delay” would not have changed the finding. And even if the project ultimately does not go forward, it would not significantly impact the ISO’s reliability margins, he said.

There will be a full discussion of the findings at the Electric System Planning Working Group’s next meeting, currently scheduled for May 6, Smith said.

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Northwest Faces Increased Fire Risk in July, BPA Says

The Northwest faces “above-normal, significant wildland fire potential” in July 2025, and the Bonneville Power Administration is taking steps to enhance mitigation efforts like public safety power shutoffs (PSPS) and improving communication. 

Citing a seasonal outlook by the National Interagency Fire Center, Kelly Miller, supervisory land surveyor at BPA, said the region is “looking pretty good until … July.” 

“In July, the significant wildland fire potential increases quickly, and we’re doing our best to prepare prior to that,” Miller said during an April 17 public update on BPA’s wildfire mitigation and PSPS processes. 

BPA is working on updates to the fourth iteration of its wildfire mitigation plan, slated for release in May 2026. However, the agency has continuously improved mitigation processes through lessons learned since the release of the first BPA wildfire plan in 2021, Miller said. 

The burn area in BPA’s service territory equaled 40.8% of the national burn area. More than 3.2 million acres burned by the end of FY24, an almost three-fold increase over the 10-year average, BPA stated in its 2024 annual report. (See BPA Hit FY24 Reliability Targets Despite Wildfires, Load Records.) 

BPA has identified several areas for improvement following extensive tests and training exercises, according to Miller. 

“We don’t always have ample advanced warning about impending weather,” Miller said. “Sometimes weather comes on very quickly, as you can imagine, and we have to make some very quick decisions. We also realize that there are many downstream load effects on the energy system that are hard to quantify, and we are working with our distribution customers to have a better understanding of that.” 

| National Interagency Fire Center

“Communication is a big piece of our public safety power shutoff events, and so we continue to make improvements to that, again, both internally and externally, how we can have more awareness for our customers,” Miller added. 

BPA issued PSPS four times in 2024, which led to five line de-energizations, according to the presentation. 

BPA closely collaborates with other agencies in its wildfire mitigation work. For example, the U.S. Department of Energy’s Pacific Northwest National Laboratory provides wildfire modeling to BPA. BPA also coordinates wildfire efforts with the U.S. Forest Service, among others. 

The agency also has explored different technological solutions, like weather sensors and smoke detection cameras “to see how we might be able to improve in the future,” Miller said. 

BPA follows industry standards and has created its own design and construction standards specific to its transmission assets, according to Miller. One notable standard implemented in 2024 includes placing fire-resistant wraps around transmission poles and installing more non-wood poles. 

Miller noted the new standards helped save multiple poles during a fire near Keller, Wash., in July 2024. 

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FERC OKs Final SPP Markets+ Compliance Filing

FERC said in a letter order April 17 that it has accepted SPP’s proposed compliance revisions to its Markets+ tariff that clarify five issues (ER24-1658). 

The commission accepted SPP’s tariff in January 2025 but asked the grid operator for further clarification in five areas: transmission availability, transmission opt-outs, Markets+ transmission contributor responsibilities, resource-aggregation mitigation and the seasonal hydroelectric offer curve’s mitigation methodology. 

FERC said the proposed revisions comply with its directives in the January order and accepted the modifications. 

SPP’s legal counsel told RTO Insider the compliance filing amounted to clarifying six sentences in its application. One of those was the same sentence written twice. 

SPP first filed its Markets+ tariff in March 2024. FERC responded in July with a deficiency letter outlining 16 issues to be addressed. The RTO’s response in January resulted in the commission’s approval. (See SPP Markets+ Tariff Wins FERC Approval.) 

Operations Review

FERC on March 31 granted in part and denied in part Basin Electric Power Cooperative’s request for transmission rate incentives for three 345-kV projects in North Dakota’s portion of the Bakken Formation (EL24-140). 

The commission granted Basin’s request for abandoned-plant and hypothetical capital structure incentive for two of the projects but denied the latter incentive for the third, the 33-mile Roundup-Kummer Ridge project.  

FERC found Basin’s request for a 50-50 debt-to-equity hypothetical capital structure incentive for the Roundup-Kummer Ridge project had not demonstrated the project had any remaining risks or challenges given that the in-service date was in the past. The line was energized in December 2024. 

All three projects were identified as part of the SPP 2021 Integrated Transmission Planning’s 10-year assessment. 

Commission Chair Mark Christie both concurred and dissented in part with a separate statement. He agreed with the capital structure incentive’s denial for the Roundup-Kummer Ridge project and dissented with the approval of the other two incentives. Christie said he dissented on the same reasoning as his prior dissents on the topic, where he has argued FERC should revisit granting such transmission incentives because they unfairly transfer wealth and risk. 

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End Users Push MISO for More Intensive Cost Overrun Evals on Tx Projects

MISO’s end users continue to call for a more stringent variance analysis, the review process MISO uses to investigate transmission projects that incur cost overruns or encounter other difficulties. 

At MISO’s April 15 cost allocation meeting, attorney Ken Stark, representing end-use customers, called for more “insight and transparency into” the variance analysis as well as a lower, 10% threshold on cost overruns to trigger the analysis. 

Stark said the Organization of MISO States (OMS), or the Independent Market Monitor, could play a role in evaluating project costs as part of the analysis. He said OMS and the IMM could sit in on MISO’s confidential initial inquiry stage, then offer advice to the RTO.  

Stark said MISO’s Board of Directors could use an expanded authority to review and issue a final determination on triggered projects, either accepting cost increases, recommending changes or making the call to suspend or cancel projects. 

The end-use sector said MISO also should consider incorporating a “feedback loop,” where after a variance analysis, MISO publishes a proposed mitigation plan open to stakeholders’ reactions over 30 days. Stark also said the RTO could file an annual report with FERC summarizing any variance analyses it performed.  

The end-use customer sector and the Coalition of MISO Transmission Customers have said MISO’s 25% cost overrun trigger to study regional projects is too high and should be lowered to about 10%. (See Stakeholders Want More from MISO on Tx Project Cost Containment.)  

MISO staff perform variance analyses on regionally cost-shared transmission projects that encounter schedule delays, permitting challenges or significant design changes or experience at least a 25% cost increase from original estimates. The studies also are triggered when developers find themselves unable to complete the project or if they default on the terms of their developer agreement. 

After completing the analysis, MISO can either let a project stand, develop a mitigation plan for it, cancel it or assign it to different developers if possible. A committee of MISO employees selected by executives makes calls on how to deal with such projects. 

Stark said SPP’s business practice manuals require projects to get a check-in at a 10% overage and undergo a review at 20%.  

“Given the sheer investment that’s happening, even a 10% overrun is significant from a cost standpoint,” Stark said. “We feel very strongly that the trigger should be lower given the lack of projects that go through the process.”  

Werner Roth, an economist with the Public Utility Commission of Texas, said he was uncomfortable with OMS conducting an additional review on cost increases in cases where projects haven’t yet been assigned a proceeding at a state commission.  

Sustainable FERC Project’s Natalie McIntire said she’s concerned a more sensitive study process would have MISO reviewing otherwise routine cost increases.  

“There are a variety of reasons for all kinds of cost increases for all products we use day to day,” she said. “We don’t want to have this sort of thing triggered for every project MISO approves.”  

Stark agreed that he didn’t want MISO to be “bogged down.”  

Other stakeholders said the IMM shouldn’t be prescribed transmission monitoring duties at a time when MISO is seeking to clarify with FERC whether the IMM should be involved in its transmission planning activities at all. (See MISO Intent on Answers as to IMM Role in Tx Planning.)  

Stark said another independent third party could evaluate projects. He said MISO could benefit from a set of “third party, disinterested eyes” to make sure MISO gets the best transmission construction outcomes.  

Some transmission owner representatives said they weren’t sure if dropping the threshold would accomplish much. American Transmission Co.’s Greg Levesque said it seems the RTO would spend more money for an independent review just to conclude the projects are necessary and should continue. 

ITC’s Cynthia Crane said the end-use customers haven’t presented a “compelling case” that MISO’s current setup is lacking. Crane said it doesn’t seem worth upending the roles and responsibilities of state regulators, the IMM and the MISO board.  

Stark said there should be more attention on containing costs for transmission projects.  

MISO maintains it doesn’t need to increase its threshold to evaluate projects. “We think we’re at the right spot,” Jeremiah Doner said.  

MISO has said it can indicate more clearly to stakeholders when it completes a variance analysis or develops an action plan. But it warned it can’t always share confidential project information. 

Staff plan to appear before stakeholders at the May cost allocation meeting with some minor edits to its variance analysis. The amendments would focus on MISO’s notification and communication commitments to stakeholders when it’s conducting a variance analysis. 

MISO is conducting one variance analysis now, investigating a 2.5-time jump in costs on one of its long-range transmission projects from its first portfolio. Incumbent developer Northern Indiana Public Service Co.’s 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana now is expected to cost $675 million, up from an estimated $261 million. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)  

“We will get to a determination this year,” Vice President of System Planning Aubrey Johnson said during March board week, though he didn’t have a specific date to expect MISO’s conclusion.