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November 5, 2024

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IBR Ride-through Standard Passes Industry Ballot

The proposed reliability standard to require ride-through protection for inverter-based resources (IBR) cleared a major hurdle last week by passing a formal ballot round after multiple previous attempts to get it over the finish line ended unsuccessfully.  

Now the way is clear for NERC’s Board of Trustees to vote on it and four other standards whose passage is required to meet FERC’s deadline of Nov. 4 to submit the first of three tranches of IBR-focused standards. Those votes are set to take place at a special board meeting scheduled for Oct. 8.  

The formal ballot for PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) concluded Oct. 4 with 158 votes cast in favor of passage and 50 votes against (with comment); 59 ballot pool members either abstained or did not vote. After applying NERC’s segment weighting, which lowers the impact from segments with fewer voters, the final result is a 77.88% weighted segment value supporting passage, comfortably above the two-thirds majority needed for passage.  

Failing to meet the two-thirds threshold would not necessarily have prevented PRC-029-1 from passage. Under Section 321 of the ERO’s Rules of Procedure — invoked for the first time by NERC’s board at its August meeting — the standard could have been considered approved with a 60% segment-weighted majority. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) 

In that case, the board would have had to solicit written public comment on the proposed standard. If satisfied the standard was just, reasonable, not unduly discriminatory or preferential, and in the public interest, it then could file it with FERC. 

The Section 321 authority also required NERC’s Standards Committee to conduct a technical conference to solicit input from industry stakeholders. At the technical conference, held Sept. 4-5 in Washington, D.C., representatives from a range of industry segments — including original equipment manufacturers and utilities — discussed their objections to the proposed standard. (See NERC, Industry Discuss IBR Issues in Technical Conference.) 

Following the conference, NERC revised the standard to address attendees’ concerns, including the clarity of the definition of “ride-through,” criteria for frequency ride-through performance and exemptions to ride-through criteria for equipment with hardware limits. Most stakeholders commenting on the revised draft felt the changes reflected opinions expressed at the conference, though many also felt more could have been done to accommodate concerns.  

In a long comment, Jens Boemer of the Electric Power Research Institute said the new draft standard “appears to be improved” and expressed appreciation for the standard drafting team for taking the comments of EPRI and others on board. However, he also indicated “further improvements” would be welcome, including: 

    • further clarification of the definitions of IBRs and the term “ride-through,” and specific grid conditions for which the ride-through requirements apply. 
    • guidance for determining the maximum capability of an IBR. 
    • exemptions for legacy equipment that may be challenging to update because of lack of manufacturer support. 

At its meeting Oct. 8, NERC’s board will vote on submitting PRC-029-1 to FERC for approval, along with the other IBR standards approved in previous ballot rounds: 

    • PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers. 
    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources. 
    • PRC-002-5 — Disturbance monitoring and reporting requirements. 
    • PRC-030-1 — Unexpected inverter-based resource event mitigation. 

The board also will consider accepting revisions to the charter of NERC’s Reliability and Security Technical Committee (RSTC) that are intended to improve the balance of industry representation at meetings. The new rules will allow a sector to seek a special election to fill an open seat representing it, rather than have that seat convert to an at-large member as the current charter provides. 

In addition, they will remove the numerical cap on the number of representatives from a sector that can serve as at-large members and will direct the RSTC Nominating Subcommittee to prioritize balanced sector representation. 

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FERC Issues Deficiency Letter for SPP’s RTO West Tariff

FERC has issued a deficiency letter over SPP’s proposed revisions to its tariff, bylaws and membership agreements intended to facilitate nine western entities’ RTO membership as transmission owners.

In an Oct. 3 letter, the commission said SPP’s filings are deficient and that it needs more information to process them. It asked the grid operator to submit its responses by Nov. 4 (ER24-2184, ER24-2185).

FERC asked for more information on:

    • Any existing tariff provisions that will facilitate the transition of the new members’ transmission service request queues into SPP’s current service-study processes.
    • The proposed tariff’s provision that the Western Area Power Administration-Colorado River Storage Project’s replacement energy is “necessitated by WAPA-CRSP’s inability to deliver sufficient energy from reservoir projects under the control of the U.S. Bureau of Reclamation in the marketing area of WAPA-CRSP for reasons such as persistent drought or environmental constraints.”
    • New metered boundaries and the need to establish a second balancing area authority that will be incorporated into SPP’s markets.
    • How separate reference buses in the market’s two balancing authority areas will accurately model the marginal cost of serving load in each BAA, including the cost of congestion.
    • How LMPs on both sides of the West DC ties will inform how SPP optimizes the interties’ usage.
    • Which rate(s) under the tariff revisions would apply to point-to-point transmission service where the load is located within a BAA external to the SPP Region but not interconnected to SPP’s eastern or western market.

SPP filed the tariff for its western RTO expansion in June as it seeks to become the first grid operator with markets in both the Western and Eastern Interconnections. It says its RTO West will provide more than $200 million in annual benefits to its members. (See SPP Files to Incorporate Western Entities into RTO.)

RTO West is scheduled to go live in April 2026.

FERC also filed a deficiency letter for SPP’s Markets+ tariff, another of the RTO’s western services. Saying deficiency letters are part of a “routine process, SPP staff responded to the letter in September and asked for an order by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

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NYISO Draft RNA Finds Reliability Need for New York City

NYISO on Oct. 4 released the first draft of its 2024 Reliability Needs Assessment (RNA) showing a capacity deficiency in New York City beginning in 2033 and proposing to declare a reliability need for its zone. 

The deficit is driven by a combination of forecast increases in peak demand and the looming retirement of small gas plants in the city, NYISO said. The analysis found that on a peak summer day with expected weather conditions (95 degrees Fahrenheit), the city would be deficient by 17 MW for one hour in 2033, rising to 97 MW for three hours in 2034. 

“This is based on the transmission security analysis and the feeding into the transmission security margin,” Ross Altman, senior manager of reliability planning for NYISO, told the Electric System Planning Working Group. “This is an actionable reliability need.” 

The declaration of a reliability need triggers a process in which NYISO solicits solutions, including transmission-based from the local transmission owners, and generation and demand response from market participants. The ISO declared a short-term reliability need for the city last year, finding a potential 446-MW shortfall by 2025. It later decided to keep two natural gas peaker plants, collectively 565 MW, in Brooklyn operational beyond their state-mandated retirement as a solution. (See NYISO to Keep Gas Peakers Online to Solve NYC Reliability Need.) 

The assessment assumes those units to no longer be available beginning in 2026. The state also recently enacted legislation to retire seven small New York Power Authority gas-fired plants in the city and Long Island worth 517 MW by the end of 2030. 

“The reliability need could be met by combinations of solutions, including new generation, retention of planned generation retirements, transmission, energy efficiency, demand response measures or changes in operating protocols,” the draft says. “Specifically, scenarios performed in the RNA indicate that the New York City transmission security deficiency could be resolved by resources currently under development but not yet in the base case.” 

NYISO had reported the possibility of such a deficiency for the city, but it had been overshadowed in meetings by a preliminary finding of a statewide shortfall of as much as 1 GW by 2034. The ISO, however, updated its assumptions about the flexibility of large loads — specifically, cryptocurrency mining and hydrogen-producing facilities — which reduced its loss-of-load expectation to less than 0.1. 

Still, the ISO warned in its draft that the LOLE is “extremely close” to the maximum: 0.094. “The tightening margins are a significant concern that … NYISO will closely monitor and re-evaluate in future [Short-Term Assessments of Reliability] and the next cycle of the Reliability Planning Process.” 

“We are just under a violation, and a big factor of that is the treatment of large loads,” Altman said. 

Large Load Flexibility

Several stakeholders questioned how NYISO determined how certain large loads would be flexible and criticized the lack of any data on the topic. 

“In your evaluations, did the cryptocurrency load representatives — whatever they are called — give you any idea about how much notice they would need to curtail their load?” asked Mark Younger, of Hudson Energy Economics. 

Altman said he did not know and that he did not want to get too detailed on what NYISO discussed with the cryptocurrency companies because such information was “proprietary.” 

“They provided enough information that [made NYISO] feel they would be flexible, either sensitive to prices or demand response,” Altman said. NYISO did not forecast the price of Bitcoin or other cryptocurrencies, he said. 

“For other resources, whether it’s SCRs [special-case resources] or generators, … NYISO has tariff provisions and other goals that require submission of information so you guys can track what’s going on,” said Kevin Lang of Couch White. “This is the only place I can think of where there’s absolutely nothing — no reporting requirements, no obligations — … and yet from the tables you’re showing us, if these loads continue to operate during peak periods, we have a very significant problem.” 

“We are engaged in bilateral discussions and surveying with these large loads in terms of the nature of these large loads and their intention to operate,” said Tim Duffy of NYISO, explaining that operating procedures and interconnection studies were also sources of information. “NYISO is really reliant upon transmission owners to gather that data.” 

“I appreciate the explanation, but I just think, given how critical this is to your assumptions, that there should be something more formalized with these loads,” Lang replied. 

Tight Deadlines, Annoyed Stakeholders

Stakeholders expressed numerous criticisms of the draft’s publications, including the lack of an executive summary: The opening section simply says “Reserved for future drafts.” 

They were also annoyed that NYISO released the draft on a Friday, with multiple stakeholder meetings scheduled that day, with a deadline for comment the following Monday (Oct. 7).  

“I am going to bust your chops,” Younger said. “The ISO needs to be rethinking the timeline that they hope that market participants can provide useful feedback on this, given how late it came out and also given that it came out at the same time that many of them are dealing with a critical step in the Demand Curve Reset, a timeline that was well known in advance.” 

Several sections, including those detailing the New York City reliability need and the narrowly avoided statewide need, were worded confusingly, stakeholders said. 

“My personal opinion is that NYISO has bungled some of the communication efforts around recent reliability reports,” said Chris Casey, utility regulatory director for the Natural Resources Defense Council. “I think it’s important for us to have time to be able to not only understand what the data and findings are, but make sure the narrative matches reality. I don’t think we were given time to do that here.” 

Doreen Saia of Greenberg Traurig requested that NYISO allow more time for discussion at the working group’s meeting Oct. 9.  

“We are going way too fast on an area that is completely charting new ground,” Saia said. 

Lang pointed out that NYISO had provided executive summaries on previous RNA reports for 2018, 2020 and 2022. 

“You are going way too fast, and you aren’t giving market participants sufficient time to understand what’s really going on here,” Lang said. 

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Electricity Bill Spikes Trigger NJ Legislative Analysis of Generation

Dramatic spikes in New Jersey electricity bills over the summer stemmed from the combined effects of an unprecedented heat wave and recent rate increases, utility executives said at a state Assembly hearing. 

Electricity use in June and July shot up by 15 to 20% in some areas over the same period in 2023 in what the New Jersey Board of Public Utilities (BPU) said was the hottest June on record. 

The Oct. 2 Assembly hearing also spotlighted the need to better cope with the state’s growing need for electricity and how to bring new generation sources online to replace retired fossil fuel sources. 

The hearing came as Gov. Phil Murphy (D) pursues an aggressive energy policy centered on electricity and the development of 11 GW of offshore wind capacity. Republican lawmakers argue the state is moving too fast and should embrace a broader energy portfolio. 

The Assembly Telecommunications and Utilities Committee convened the hearing in response to widespread customer complaints about the sudden increase in the size of their bills. 

“I received countless calls from my constituents because they are seeing what I have been seeing — skyrocketing electric bills,” Assemblywoman Andrea Katz said in testimony to the committee. “I heard it from my neighbors, and I saw it on my own electric bill. Utilities like Exelon have seen their stocks up 10% over the last year, while at the same time, families in New Jersey are paying hundreds of dollars more a month for their electric bills. … And we all need answers.” 

BPU President Christine Guhl-Sadovy said the “main driver of the increases over the summer was an increase in usage.”  

Customer use across the four utilities that serve the state — PSEG, Jersey Central Power & Light, Atlantic City Electric (ACE) and Rockland Electric Co. — increased by 12 to 16% over the previous year, which was relatively cool with unusually low use, she said.  

In addition, she said, the BPU certified a rate hike that would increase the average customer bill by 5 to 8% due to electricity rates set in the Basic Generation Service (BGS) auction held by the four utility companies. 

Multiple Rate Hikes

Brian O. Lipman, director of the New Jersey Division of Rate Counsel, said the rate hike was one of several implemented by utilities that affected customers for whom, given the elevated temperatures, “air conditioning is no longer a luxury, it is life saving.” 

In testimony, and in a supporting letter to the committee, he said ACE had increased rates nine times since July 2023, and reduced rates four times, for a net overall increase. These included increases for transmission rates, infrastructure improvements, and prices set by the BGS results, which increased electricity supply rates by about $7.56 per month, he said.  

Even before the use increase, the average ACE ratepayer was paying about $23.64 more in June 2024 than a year earlier, Lipman said. 

Add during the heat wave and “the result is significantly higher bills for ACE customers in the summer of 2024 as compared to the summer of 2023,” he said in the letter. “This analysis does not only apply to ACE. I could go through the same analysis for PSE&G, JCP&L and Rockland Electric Co.” 

Speaking at the hearing, Phil Vavala, ACE’s regional president, said the average customer bill increased by 20%, part of which was due to the “pass-through” cost of electricity rates, which are set at the BGS auction. 

He said the company works to “empower customers to better manage their energy use.” That includes providing customers with programs that “help those who are struggling to meet their energy needs” and to deploy smart meters that enable customers to better monitor their energy use, he said. 

Electricity Demand Surge

Several speakers said the spike in customer bills showed the state has to address far larger systemic issues. 

“One of the main takeaways that we probably will all share today is that we do need more generation,” Guhl-Sadovy said. “We, over the last couple of decades, have not seen a significant demand increase in energy use, in part because we’ve done a really good job in energy efficiency. And so we’ve helped to keep that demand flatter. But we have seen energy demand go up, and so we do need more generation.” 

BPU officials said at an Oct. 1 hearing into the agency’s offshore wind infrastructure solicitation that they expect demand for electricity in the state to increase by 15,000 GWh to 93,000 GWh by 2025. (See related story, NJ Offshore Infrastructure Plans Spark Electromagnetic Fears.)  

Jason Stanek, executive director of PJM Interconnection, which serves 13 states, said the region is in the midst of a transition. 

“We’re seeing a tightening of supply and an increase in demand,” he said. “And they’re going in opposite directions relatively quickly.” 

He said the RTO’s load forecast released earlier in the year showed trend lines that were “head and shoulders above all prior years.” That increase stems in part from the rise in electric vehicle use and the emergence of commercial high-energy users such as data centers and artificial intelligence facilities, he said.   

An example of the challenge facing PJM, he said, is that in the 12 months prior to the summer of 2024, the RTO experienced 4,000 MW of generating source retirements, while peak demand rose by 4,000 MW.  

“So that’s an 8,000-MW difference in just a short period of 12 months,” said Stanek, adding that such a sudden increase in demand is difficult for PJM to handle. A shortfall in supply compared to demand can increase the price of electricity. That was demonstrated in the results released in July of the organization’s recent capacity market auction, which set electricity prices nearly 10 times higher than a year ago, he said. 

Stanek urged lawmakers to help PJM, and the region, better handle the ongoing demand surge by avoiding policies that are “designed to push resources off the system before we have an equal and equivalent amount of replacement resources.” 

At the same time, PJM is working through a backlog of customers waiting to connect new sources to the system, he said. 

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NYISO Working Group Meeting Briefs: Oct. 1-2, 2024

Proposed RS1 Carryover for 2025 Increases

Things got a little testy at the NYISO Budget and Priorities Working Group meeting Oct. 2 when Cheryl Hussey, the ISO’s chief financial officer, presented some final updates to the proposed 2025 budget.

Hussey said NYISO was proposing to increase the Rate Schedule 1 carryover to $5 million. In September, Hussey explained that the ISO is expecting a surplus this year because of overcollections under RS1, the administrative rate used to recover operating costs from members. (See NYISO Proposes Increased Budget, Admin Rate for 2025.)

“That’s really the only change to the actual budget itself to date,” said Hussey, who went on to explain that this would reduce the budget to $202 million, a $2 million decrease from what she previously presented. This would result in an RS1 surcharge of $1.306/MWh instead of $1.319/MWh. Hussey said that higher projected overcollections were being used to reduce RS1 instead of paying outstanding debt.

“Can you share your analysis that shows that this is actually in the customers’ best interest to use this money as a one-time carryover rather than paying down debt?” asked Kevin Lang, a lawyer representing Multiple Intervenors and New York City. “We had pushed for paying down debt years ago because we understood at that point in time that that was really the best use of it. … I don’t see any analysis at all. I just see a statement here.”

Hussey said the interest rates NYISO was paying on its debt were quite low and that the numbers were just projections but that if NYISO had extra funds they were able to use them to pay down debt early.

“If stakeholders would rather us not have a carryover to reduce next year’s budget, that’s fine. I’ve asked for that feedback,” Hussey said.

“I’m not asking for that, Cheryl. I’m simply asking for the analysis you guys did,” Lang said. “We’re paying for all of this. You guys aren’t a confidential entity, and you’re saying you’ve done an analysis that shows this is the best use. I’m not saying, ‘Don’t do it.’ I’m simply saying I’d like to see the analysis so we can better understand that.”

Hussey said NYISO would need to review its agreements with its banks to see what information she could share.

Lang replied that he had seen more detailed budgets from other grid operators and suggested that if NYISO wasn’t willing to share more detailed budgetary information, then perhaps it was time to revisit auditing its management.

“I know you’ve been completely opposed” to an audit, Lang said. “But the [New York Public Service Commission] has that authority. The FERC has that authority. Maybe it’s time that we take a closer look at some of these issues.”

Hussey said she was not refusing to share the analysis, but Lang retorted that she had not agreed to provide it, either.

How to Value Transmission Security

The Installed Capacity Working Group meeting Oct. 1 was dominated by a discussion of the different ways that NYISO could incentivize transmission security via the markets.

The Market Monitoring Unit and several stakeholders have raised concerns about how transmission security requirements are incorporated into the ICAP market at minimum levels. The worry is that the current market structure does not correctly incentivize or value transmission security, leading to repeated regulatory and public policy interventions to build out the transmission system. (See “Demand Curve Reset and Transmission Security,” NYISO ICAP Working Group Briefs: Sept. 24, 2024.)

But how to value transmission security is an open question.

“We would have separate requirements, curves and accreditation for resource adequacy and transmission security, priced separately,” said Manish Sainani, NYISO market design specialist, outlining the Monitor’s proposal.

“You’ve just described something that’s drastically more complicated than having separate requirements and doing a joint solving program,” said Mark Younger, principal of Hudson Energy Economics. “It seems what you’re proposing is an even bigger kludge than what we have in the market today.”

Later in the discussion, NYISO clarified that its presentation was just trying to identify potential options but that none of them had been decided on yet.

“It seems like one of the first things we should try to nail down is the methodologies for calculating TSLs [transmission security limits] and [locational capacity requirements]; that’s been underway for a while,” said Mike Mager, a lawyer from Couch White representing large energy consumers. “I don’t think it makes a ton of sense to change the market for TSLs when we’re not even positive what the methodology is for calculating them.”

Monitor Pallas LeeVanSchaick said TSLs are having a major impact on the market.

“It’s having a big impact today, and it’s going to have a bigger impact in the future,” he said. “I think our proposal was just trying to make a refinement to the market so that it is having an appropriate impact.”

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Texas Politicos, Residents Bash CenterPoint

HOUSTON — Returning to the “scene of the crime,” as Houston state Sen. Molly Cook (D) put it, the Texas Public Utility Commission made a rare trip out of Austin for a public hearing as it investigates CenterPoint Energy’s heavily criticized response to Hurricane Beryl in July. 

The Category 1 storm appeared to catch CenterPoint off-guard and knocked out power to more than 2 million of its customers. The Houston utility was excoriated for its poor communications, an outage map that didn’t work and lack of outreach to the community. At least 40 deaths have been attributed to the storm, many related to the extreme heat (indexes reached 106 degrees) during the outages that extended into a second week. (See CenterPoint Energy Still in Eye of the Storm.) 

Texas Lt. Gov. Dan Patrick (R), a Houston-area resident since 1979, was not on the agenda but opened the Oct. 5 hearing with 30 minutes of prepared remarks. Saying he had no “personal animus” toward CenterPoint, CEO Jason Wells or anyone on the commission, Patrick suggested the utility needs a new leader and threatened the PUC with using the Senate’s subpoena power to conduct its own investigation. 

“CenterPoint should have been prepared three and four days after that storm hit Houston, and they were not,” Patrick said. “We were at the state level. They were not. Had they been prepared, I believe much of the misery and damage after the fact would have been averted. 

“So, it’s not personal, Mr. Wells. We’ve had good discussions, but CenterPoint needs to have a strong leader who will have foresight, not look back in the rearview. ‘Oh, we’ll fix it now,’” he said. “I believe at this point, the board of CenterPoint should ask for Jason Wells’ resignation, or I believe he should submit it.” 

CenterPoint Energy CEO Jason Wells listens to public comments during the PUC hearing. | © RTO Insider LLC 

Patrick noted he returned home from California several days before the storm’s July 8 landfall when it became apparent Beryl would hit Texas. A National Weather Service representative backed him up, testifying that the agency had a tropical storm warning in effect July 6 and then expanded it to inland warnings. 

“It was a terrible wind event that brought down the trees and power lines and traffic lights. We know all of what happened, but [CenterPoint was] slow,” Patrick said. “They were slow in preparation, procrastination and then communication. People didn’t know where to turn. No one could get a response. It was the poorest response to citizens and elected officials trying to reach them.” 

Citing state rules, Patrick said the PUC has the right to audit and review CenterPoint’s management and business operations. Consumer advocates have said the utility has been overcharging customers for years. 

“I expect you to do that audit,” he said. “I want to know how much they have been overcharging, if they’ve been overcharging the customers at CenterPoint, and for how long. We need that answer.” 

The lieutenant governor also upbraided the PUC for its approval of 2021’s $800 million lease of generators, some designed to restore power to entire neighborhoods but that weren’t used in Beryl’s aftermath. The commission approved CenterPoint’s cost recovery — about $350 million so far —over an administrative law judge’s recommendation. 

“If the commission doesn’t act on the $800 million, if they don’t act on the right cases, if the commission does not act on looking [into whether customers] have been overcharged, then our [state Senate] Business and Commerce Committee will be given subpoena power to get the answers,” Patrick said. 

“I want to know about that $800 million. I want to know why it was signed … I want to know why it was overturned,” he continued. “If the PUC allows CenterPoint to get away and try to PR their way through this, that will show the commission is not accountable.” 

As lieutenant governor, Patrick controls the Senate’s agenda. Two of the PUC’s commissioners, Chairman Thomas Gleeson and Courtney Hjaltman, have not yet been confirmed by that legislative body. 

“I know how personal this is to you,” Gleeson told Patrick when he wrapped up his comments. “Thank you for your leadership, and I know you’ll continue to hold this commission and everyone accountable to make sure we get the right results.” 

Lt. Gov. Dan Patrick | © RTO Insider LLC 

About six hours after the hearing began and some 30 local residents had complained about CenterPoint, Wells took the stand and “personally” apologized to those still present. 

“The number of outages [was] too high, the … outages were too long, and our communications did not meet your expectations,” he said. The CEO said CenterPoint has not been overcharging customers and frequently earned less than it could have. 

Darin Carroll, CenterPoint’s senior vice president of operations, provided an update on the utility’s Greater Houston Resiliency Initiative to better prepare for the next major storm or hurricane. CenterPoint expects to spend about $550 million during the plan’s current phase on 25,000 poles that can withstand extreme winds and undergrounding 400 miles of lines, among other items. 

The company plans to invest $5 billion in the Houston system between 2026 and 2028. It will file a long-term plan by Jan. 31. 

The PUC also discussed best practices with industry veterans of previous hurricanes, including two former Florida Power & Light employees, and representatives from the Edison Electric Institute and the Southeastern Electric Exchange. Florida has been held up as a positive example of grid hardening following eight major storms in two years. 

The commission will continue to take customer feedback through Oct. 9. It will file its report and recommendations for changes to Gov. Greg Abbott and the legislature by Dec. 1. 

“We heard loud and clear that you expect better from your electric utility, and we plan to use your feedback to ensure Houston-area utilities are prepared the next time extreme weather hits,” Gleeson said after the hearing in a statement. 

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CAISO Board Approves Moving Forward with SWIP-N Transmission Line

The CAISO Board of Governors on Oct. 4 unanimously approved changes to the Southwest Intertie Project-North (SWIP-N), a 285-mile, 500-kV line in Nevada that would enable access to Idaho wind resources, despite opposition from Gem State residents.

In April, the Department of Energy signed a facilitation agreement to provide $33.1 million to fund Idaho’s potential 22.831% share of the project to expedite the process. CAISO had asked the board to approve two motions: to allow the DOE funding, and to approve project developer Great Basin Transmission’s application to become a participating transmission owner in the ISO.

The project would enable CAISO to meet the California Public Utilities Commission’s Integrated Resource Plan requirements, which call for just over 1,000 MW of Idaho wind power in the 2024-2025 transmission planning cycle. According to transmission planners at the ISO, SWIP-N is the only known transmission project that would provide California load-serving entities with Idaho wind by 2027.

While SWIP-N was conditionally approved by the board in December 2023, moving to the construction phase still relied on the approval of the two motions.

“Unlike a project directly assigned to an incumbent transmission owner under the Transmission Control Agreement, this did not move the project straight to execution,” Neil Millar, vice president of infrastructure and operations planning at CAISO, said at the board’s meeting.

Deb Le Vine, executive director of infrastructure contracts and management at CAISO, presented details on the status of the project, as well as the two motions. The project was initially approved under four conditions: that Idaho Power file and receive approval for the project with the Idaho Public Utilities Commission by Sept. 30; that the California PUC reaffirm the need for Idaho wind in its 2024-2025 transmission planning process portfolio; that Great Basin declare its intent to become a PTO by July 1; and that FERC accept Great Basin’s proposed tariff and transmission revenue requirement rate structure.

Idaho Power has not yet filed with the Idaho PUC, meaning that FERC has not yet approved Great Basin’s tariff. The other two conditions were met.

“It’s critical to enable Idaho wind to reach California, consistent with the CPUC system plan,” Le Vine said.

Opposition from Idaho Residents

While SWIP-N isn’t tied to any specific generators in Idaho, some residents opposing the Lava Ridge Wind Power project and others in the region expressed concern about SWIP-N.

Dan Sakura, a fourth-generation Japanese American whose ancestors were interned at the Minidoka War Relocation Center in Idaho — a National Historic Site — said the area is now located in a “dense transmission network” because of its proximity to a railroad. Sakura, along with the Seattle-based Minidoka Pilgrimage Planning Committee, has been fighting LS Power since 2009 when it sought to build the SWIP-N line over the site. The organization is also fighting the Lava Ridge Wind Project, which it believes to be associated with SWIP-N.

Sakura asked the board to delay its decision until its meeting in December to allow for more time to “get a better analysis of the legal, regulatory, policy and electoral risks associated with wind energy from Idaho.”

Another Idaho resident, Dean Diamond, a farmer whose property borders the Minidoka site, echoed Sakura’s concerns.

“There is a lot of strong local opposition to the SWIP line and to the wind projects. I think that it poses a really significant risk that the wind projects most likely aren’t going to be built,” Diamond said.

“We’re not aware of that high opposition, just an attempt from those against the wind projects to link SWIP-N to that,” responded Mark Milburn, senior vice president of LS Power. “I think it’s also important to address that the commenters thus far haven’t acknowledged that in [the Bureau of Land Management’s] preferred alternative for the final environmental impact statement for the Lava Wind Ridge Project, they significantly scaled back the project to address the concerns raised by different stakeholders in that process.”

Milburn noted that the project footprint was reduced by 50% and the number of turbines by 40%, along with a 10% reduction in turbine tip height.

Board Chair Jan Schori thanked the commenters for participating in a process that “can be quite challenging to understand.”

“We do appreciate the fact that you’re participating with us today and helping educate us,” Schori said.

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DC Circuit Affirms FERC Ruling on Seabrook Circuit Breaker Dispute

The D.C. Circuit Court of Appeals has affirmed FERC’s ruling that NextEra Energy is responsible for replacing the circuit breaker at its Seabrook Station nuclear plant to accommodate the interconnection of the New England Clean Energy Connect (NECEC) transmission line.

ISO-NE determined the circuit breaker at Seabrook, currently at 99.6% of its capacity, would be overloaded with the additional flow of power from Avangrid’s 1,200 MW NECEC project, which is under construction. (See Avangrid Details Progress on NECEC Tx Line.)

While FERC found Avangrid is responsible for the direct costs of upgrading the circuit breaker, it ruled Avangrid is not responsible for NextEra’s indirect costs of the replacement, including legal expenses and revenue lost during the replacement.

“We hold that the agency had statutory authority to require the upgrade, correctly interpreted the governing tariff and contract to require the upgrade, and permissibly denied compensation for its indirect costs,” Judge Gregory Katsas wrote in the court’s Oct. 4 ruling.

NextEra argued the circuit breaker is non-FERC jurisdictional because it exists to protect the generating facility, and so the commission doesn’t have the authority to require NextEra to make the upgrade (EL21-3, EL21-6). (See FERC Resolves NextEra-Avangrid Dispute over Seabrook Circuit Breaker.)

The court found the upgrade is FERC jurisdictional because “the upgrade directly affects the transmission of electricity in interstate commerce, an area where FERC may regulate.”

“If FERC could not order an upgrade in those circumstances, incumbent generators could unilaterally prevent competing sellers from joining the grid, which would directly — and substantially — limit how much electricity could be transmitted,” the court added.

The court also pointed to a previous ruling that backed FERC’s ability to “exercise jurisdiction over generation facilities to the extent necessary to regulate interstate transmission.”

Judge Neomi Rao authored a dissent to the majority ruling, arguing the language in the ISO-NE tariff does not require NextEra to replace the circuit breaker, and therefore the company should not be required to make the upgrade, regardless of the implications on interconnection in the region.

“The broader regulatory context and policy concerns cited by the majority may be relevant to FERC’s determinations when setting just and reasonable rates and practices. These considerations, however, are impermissible for the judicial task of identifying the plain meaning of existing tariffs and contracts,” Rao said. She added that FERC could initiate a Section 206 proceeding to amend the tariff if it deems changes to be necessary.

Rao also argued the majority opinion “reverts to a Chevron-like framework, insisting its interpretation is ‘textually permissible’ and consistent with regulatory goals.”

In response, Katsas wrote that the RTO’s interconnection procedures require NextEra to follow “good utility practice” to maintain the breaker and other devices needed to prevent short-circuiting on the grid, adding that the tariff does not grant NextEra “a unilateral right to veto Avangrid’s interconnection.”

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EFI Foundation Showcases Minnesota Clean Energy Jobs Sector as Model for Midwest

Minnesota’s economy is reaping the benefits of promoting a clean energy workforce, said state regulators, union leaders and utility representatives in a webinar.  

EFI Foundation, a D.C.-based nonprofit dedicated to furthering the clean energy transition, held Minnesota up as a success story for other Midwestern states to follow during its Oct. 2 webinar on clean energy workforce development.  

“Minnesota is a great example of making some real progress,” EFI Foundation CEO and former U.S. Energy Secretary Ernest Moniz said.  

Minnesota Department of Commerce Deputy Commissioner for Energy Pete Wyckoff credited the Inflation Reduction Act and the Infrastructure Investment and Jobs Act for greasing the wheels to create quality jobs to build the next-generation workforce in the state. 

He said Minnesota is a key player in “building out and rebuilding our manufacturing sector.”  

Minnesota Public Utilities Commission Chair Katie Sieben said in the past six to seven years, the commission has gotten better at including community and workers’ voices in its dockets and decision-making. She said the commission in some cases has required utilities to file worker transition plans when fossil generation is retired.  

Sieben said state regulators now ask developers if they plan to use local labor in their projects.  

“In Minnesota, we want the workers to come from Minnesota. We don’t want them to come from Texas and Florida, no offense to those states. … We’re asking how we make these projects Minnesota-based,” Sieben said.  

Wyckoff also said Minnesota’s legislature redesigned its permitting process at the state level. He said he thinks projects now can move faster “without compromising the public input.”  

“If the federal folks want to know how they can do this, they can give us a call. Sometimes we lead and sometimes we follow,” Wyckoff joked.  

Sieben said Minnesota sees its infrastructure is aging and needs “intense investment” in transmission to achieve clean energy targets.  

Wyckoff said federal funds are key to reducing “energy activation costs” and accessing the cheaper energy that’s on the other side of the energy transition.  

Siebe noted that federal funds are at play for the reinventing of the Sherburne County Generating Station, where Xcel Energy plans an iron-air battery system pilot and the 710-MW Sherco Solar project, set to become Minnesota’s largest solar facility.  

Xcel Energy Vice President for Regulatory Policy Bria Shea said her utility contemplated how to take advantage of the significant interconnection rights and existing infrastructure of the coal-fired Sherco plant.  

She said the first 260 MW of the expansive solar farm should go into service next week.  

Minnesota Power Vice President of Regulatory and Legislative Affairs Jennifer Cady said an energy transition that leaves behind workers is “simply neither just nor sustainable.”

Jennifer Cady, Minnesota Power | EFI Foundation

Cady said Minnesota Power built three solar farms using panels from Heliene’s facility in Mountain Iron, Minn., to help the state bounce back economically from the pandemic. Cady added that Minnesota Power has contracted with local farmers to use sheep for vegetation management around the panels.  

Minnesota Power now has supplier preferences for local companies, Cady said. The company recently announced it plans to build two utility-scale solar projects in northern Minnesota by 2027, one of which will be at the Boswell Energy Center, Minnesota Power’s last active coal plant. 

“I know new technologies can almost always be disruptive to local jobs,” EFI Foundation Distinguished Associate David Foster said. Foster said it’s important to showcase that Minnesota’s brand of industrial collaboration paired with federal support is driving job creation in the state.  

Rick Martagon, executive director at Minnesota building trades apprenticeship preparatory program Building Strong Communities, said the program this year graduated its largest cohort yet at 106 of 125 attendees.  

Joe Fowler, business manager at Laborers’ International Union of North America (LIUNA), said good relations between laborer organizations and utilities can help ease the disruption of the energy transition.  

“It’s saying, ‘How do we make sure those careers continue?’” he said.  

“There are new opportunities to replace the old ones if people are willing to be retrained,” he said, adding that the economic benefits of good jobs are multiplied when laborers spend dollars within their communities.  

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NJ Offshore Infrastructure Plans Spark Electromagnetic Fears

Citing predictions of a 20% rise in New Jersey’s electricity demand by 2034, state officials laid out an infrastructure plan to tie offshore wind projects to the grid at a public hearing Oct. 1 amid skepticism about the safety of running high-powered cables through residential areas. 

Speakers from the New Jersey Board of Public Utilities (BPU) said at the hearing on the agency’s OSW infrastructure solicitation that the state needs extensive support for the dramatic increase in electricity supply to meet demand. 

The BPU said coordinated developments to tie three or four projects to the shore, instead of several developments each running their own cables inland, would be more efficient, less disruptive to the community and could save hundreds of millions of dollars. The agency will collect comments on the plan until Oct. 15. 

“We’re talking about 15,000 GWh of electric demand,” said Bob Brabston, BPU executive director, of the expected increase. “That’s driven by a host of things, including economic development through port electrification, data centers, the growth in electric vehicles, larger homes and population growth in the state.” 

The BPU seeks proposals on how to build a corridor linking the Sea Girt National Guard Training Center on the shore, to infrastructure under development at Larrabee Collector Station inland. That station would link to the grid and was approved in an earlier $1.07 billion infrastructure solicitation. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

Four developers have submitted proposals for the second infrastructure solicitation, which the BPU launched in November 2023. The BPU said it expects to pick projects in the coming weeks, with construction expected to start in 2027 and end in 2029. The developers would build duct banks, conduits or pipes through which the cables run, and cable vaults, which are concrete boxes that house the connection point of two long stretches of cable and can serve four offshore projects, with the actual cables installed later. 

A series of speakers at the hearing — held at the office of the International Brotherhood of Electrical Workers Local 400 in Wall Township, N.J. — said they were worried about the community disruption from laying cables and the safety of having them so close to residences. The BPU said about 450 people signed up to attend live, and an additional 75 registered online. Environmental groups and other OSW supporters held a rally before the event. 

Mayor Don Fetzer of Sea Girt and Mayor Mike Mangan, of neighboring Manasquan, said resident concerns were widespread and urged state officials to consider the demands of local communities. 

“This is not anything against wind turbines,” Fetzer said. “We’re not against alternative energy. What we’re against is more the process, and how they came into our streets when there are other (possible) areas that we feel are well known.” 

He said the borough had spoken to the four developers and that officials attended a meeting of 600 people a few weeks ago organized by a group called Stop the High-Risk Power Cables. 

From the outside, the cable route landing point “seems like a natural place owned by the state, not a parkland, nothing like that,” he said. “And what has always been infuriating to us as a town is it would make a hard north turn after they made the beach and run into Sea Girt proper on our residential streets. And that’s been the main focus of our complaints and concerns.” 

The exact route has yet to be determined, the BPU said. 

Changing Strategy

The BPU initially sought offshore infrastructure with the onshore solicitation conducted under FERC Order 1000’s State Agreement Approach (SAA). But the BPU changed its plan and decided the offshore infrastructure — known as prebuild infrastructure (PBI) — should be part of the state’s third OSW solicitation. The BPU then shifted course again in October 2023 to create a separate infrastructure solicitation, and in February initiated a second SAA. (See NJ Revamps Third Solicitation OSW Connection Plans.) 

BPU officials said at the hearing that offshore wind is needed to meet the demand increase because New Jersey relies on 6,000 MW of electric power brought in from out-of-state generators. Much of the imported power is produced during critical periods by coal plants, agency officials said. 

The BPU since 2019 has completed three OSW project solicitations and approved five projects. It is midway through a fourth solicitation, with a fifth expected to begin early in 2025. Danish developer Ørsted withdrew two of its projects a year ago, while another project approved in the second solicitation, the Atlantic Shores, is now the state’s most advanced of three remaining projects. 

Underground Drilling

The PBI solicitation seeks proposals to build two 320-kV transmission lines and two 525-kV transmission lines. Duct banks would be buried five feet below ground, BPU officials said. And there would be no trenches or excavation on the beach. Instead, horizontal channels would be drilled 60 feet beneath the beach and pipes inserted, ready to be filled with cables, officials said. 

“There’s no excavation at the beach,” said Nicolas Baldenko, an engineer for consultant Levitan & Associates, which is helping the BPU evaluate the submissions. “Beach landings for cables everywhere around the world, whether it’s power or communications, those are always done nowadays via something that’s called horizontal directional drilling,” he said. 

Katharine Perry, BPU’s deputy director of offshore wind, said the agency will evaluate the infrastructure projects based on their viability and cost and to ensure “any successful project results in the least disruptive approach.” 

To that end, “during construction the selected developer would be responsible for ongoing and active communication with local communities to ensure any construction activities follow all requirements to minimize disruptions and maintain the highest safety standards during construction,” Perry said. 

BPU officials cited several existing examples of similar high-voltage cables in the New York-New Jersey area, most prominently the Neptune Regional Transmission System, a 5,000-kV direct current underground cable that runs from Sayreville, N.J., to Jones Beach on Long Island. 

Magnetic Field Fears

Those examples did little to quell residents’ fears. Several speakers focused on possible health damage from high-voltage electricity cables running close to their homes and of a proposed route they said would take the cable through an EPA Superfund site formerly occupied by two dry cleaning operations, White Swan Cleaners/Sun Cleaners. 

“A program of this magnitude and proximity to a developed community is untested and consequential health and safety issues have not been adequately established,” said Fred Marziano, a Sea Girt resident. He said the EPA has said, with regard to the Superfund site, that “spreading of the contaminated plume in our groundwater would be very likely if disturbed.” 

Manasquan resident Lynette Viviani said the cable would pass “30 feet from my living room.” She asked “what kind of monitoring” state and federal agencies would do to ensure the Superfund site did not spread pollution. 

Glenn Hughes, another Sea Girt resident, said the existing cables cited by the BPU aren’t relevant because the voltage on the proposed cables is significantly larger. Moreover, the Neptune cable “does not go through a single residential neighborhood,” he said.  

No one can say “with any certainty that this is going to be safe,” and “nobody living in America should have to live with that risk,” Hughes said. 

The BPU earlier showed a video in which Benjamin Cotts, an engineer specialist in magnetic fields and cables, minimized the possibility of health impacts from the cables. Cotts, who works for an engineering and scientific consulting firm hired by the BPU, said the cables would carry direct current (DC), and not alternating current (AC), which is most commonly used and studied. Any discussion of electric-magnetic fields relating to AC is “completely irrelevant,” he said. 

He said, “the cable construction and the burial below ground will effectively block any electric field from the cables,” and added that the DC magnetic fields created by the PBI would be too small to harm anyone.  

The World Health Organization has determined the acceptable limit for DC magnetic fields is 4 million milliGauss (mG), he said. And “the upper range of the DC magnetic fields from the prebuilt infrastructure is expected to be less than one-half of 1%” of that level, he said. 

BOEM Approval

In an unrelated development, BOEM announced on Oct. 1 its approval of the construction and operations plans for part of New Jersey’s most advanced project, Atlantic Shores South 1 and 2, which are 8.7 miles from the New Jersey shore and together will generate 2.8 GW of power. The company said they will serve 1 million homes. 

“Securing these critical approvals enables New Jersey’s first offshore wind project to start construction next year and represents meaningful progress in New Jersey achieving 100% clean energy by 2035,” said Joris Veldhoven, CEO of Atlantic Shores Offshore Wind.