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November 14, 2024

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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. 

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Regulators Who Launched Pathways Praise Western ‘RO’ Plan

State utility commissioners who launched the West-Wide Governance Pathways Initiative in July 2023 have praised the initiative’s “Step 2” proposal to create a “regional organization” (RO) to oversee a Western electricity market and gradually take on more functions of an RTO.  

“I’m really, really struck by the power of what has been proposed,” Oregon Public Utility Commissioner Letha Tawney said during an Oct. 4 Pathways Initiative meeting to discuss the plan. 

The Pathways Initiative’s Launch Committee released the proposal Sept. 26 after a year of discussions and a summer of intensive stakeholder workshops. (See Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’.) 

The plan, which calls for the RO to launch under the “Option 2.0” refined over the past year, would see the new organization initially serve as a “policy-setting” body for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), operating under a tariff shared with the ISO. 

The proposal defers the adoption of an “Option 2.5” in which the RO takes on more of the ISO’s responsibilities and liabilities, leaving that decision to the RO and its board in the future.    

Tawney was one of nine Western state energy commissioners to sign the July 2023 letter that kicked off Pathways by proposing “creation of an entity that could serve as a means for delivering a market that includes all states in the Western Interconnection, including California, with independent governance.” 

The commissioners sent the letter to the chairs of the Committee on Regional Electric Power Cooperation and Western Interstate Energy Board just as SPP’s Markets+ day-ahead offer emerged as a serious challenger to the EDAM and WEIM, raising the prospect that the West could become divided into two markets separated by a complex seam, depending on the footprints of each. (See West Entered Pivotal Period for RTO Development in 2023.) 

“At its core,” Tawney said, the new Pathways proposal intends to “set up real parity between the [CAISO] BA and all of the other BAs in the West” and puts “everybody on the same footing, making decisions at the timing that works for them, for their community, for their regulatory agencies or bodies.”  

“It is really creating an opportunity for customer value that we had hoped would be there when we put the letter out, and it’s exciting to see it really emerge in the framework that is encapsulated in this proposal” she said. 

New Mexico Commissioner Pat O’Connell said he took a “leap of faith” when he helped write the letter. 

“One thing that I just wanted to acknowledge in this moment is congratulations to the Launch Committee for getting to this point — and then thank you very much to the stakeholders for helping build it up to this point,” O’Connell said. 

“So just in a moment where we went from leap of faith to now, I can see it: that this idea that the largest possible footprint is [viable] and that we could maximize consumer benefits that way,” he said. 

O’Connell said much of the analysis that utilities and other entities have performed has “put the math behind the concept” that consumer benefits increase “if we can get to the widest possible footprint.”  

A recent study by The Brattle Group found New Mexico’s utilities would see greater financial benefits from joining EDAM rather than Markets+, even if Arizona utilities were to join the latter. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.) 

“I don’t want to sugarcoat it — there’s still a lot of work to do — but this is an important milestone, and the fact that there are so many folks on this [Pathways] call this morning is another affirmation that the idea was sound,” O’Connell said. 

“This has just been a tremendous process with so many different stakeholders from across the West looking to create something that’s going to work for the entire West,” said Darcie Houck, a member of the California Public Utilities Commission, whose president, Alice Reynolds, signed the letter. “I’ve just have been very, impressed with the process, the engagement by all of the different states and stakeholders, and [am] really looking forward to seeing the comments that are coming back and moving forward on the next step.” 

‘Unreasonable Ask’

Tawney said the failure of previous attempts to transform CAISO into an RTO couldn’t be attributed to “a lack of trying by a lot of really thoughtful folks over many years.” 

Tawney said she understood why California lawmakers had been reluctant to pass a bill that would relax state oversight over the ISO and place it under independent governance. 

Requiring one balancing authority to “regionalize” itself ahead of other BAs is “unreasonable,” she said. 

“Because if somebody had come to me and said, ‘I want to take [Portland General Electric’s] balancing area and put it under regional governance, and maybe some folks will join me later,’ I’d have immediately said, ‘What about PGE’s customers?’ … And I might have had a big reaction [and said], ‘No, I think we will be keeping those decisions to protect PGE customers a little closer to home,” Tawney said. 

Tawney said Pathways showed that stakeholders across the West are “deeply aligned on protecting our customers, on protecting affordability, on thinking through reliability and how we can all work together,” put participants on “equal footing” and allowed each state to move at its own pace in deepening the relationship with the RO. 

Launch Committee Co-Chair Pam Sporborg, PGE’s director of transmission and markets, said the Step 2 proposal differs from past regionalization efforts because it focuses narrowly on governance of the energy market, rather than taking on all the functions of an RTO at once. 

The plan also establishes a “parity relationship” between CAISO and other EDAM/WEIM participants by allowing the ISO to maintain its balancing authority reliability functions — just like other BAs — while handing oversight of the joint market to a “fully independent governance structure,” Sporborg said. 

Committee member Scott Miller, executive director of the Western Power Trading Forum, said the committee “wrestled with” the question establishing the RO under the “lighter touch” of Option 2.0 or the “more robust” 2.5.  

“There was good, healthy debate, and I think where we ended up reflected the good nature and well-intentioned efforts of the Launch Committee to try to reach compromise that met everybody’s needs,” Miller said. 

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Exelon, Constellation at Loggerheads over Data Center Co-location

The dispute between Exelon and Constellation Energy continues to play out in FERC, as the latter and others have protested a series of filings from the former’s utilities seeking to implement new rules for co-locating data centers at power plants in their territories (ER24-2894).

“Pepco supports the opportunity for end-use load customers to co-locate where it can be done without threatening reliability. Because the new loads are end-use customers, state law, rather than the [Federal Power Act], determines the retail rate treatment of these arrangements,” the Exelon subsidiary said in its proposal, submitted in August along with those of its five sister utilities.

Ahead of the deadline for comments on the proposals, Exelon petitioned FERC on Sept. 30 for an order declaring that PJM’s generator interconnection procedures under Order 2003 apply only to end-use generation, not load. (See related story, Exelon Asks FERC to Weigh in on Co-location Dispute with Constellation.)

Exelon’s utilities argue in their filings it’s important that co-located customers bear their fair share of the costs of transmission service they use and of the interconnection facilities. Even data centers on the generator side of the meter impose similar needs on PJM when it comes to ancillary services and RTO monitoring and administration, they said.

The changes would require any co-located data centers to pay their share of the cost of transmission services, ancillary services and other PJM charges. Exelon also initially said it would be required to meter the “gross load” of the end-use customer, but it removed that language after a protest from the Natural Resources Defense Council saying that could impact backup generation many customers use.

Constellation argues in its protest that any data centers that might connect to its nuclear plants in PJM — and in Exelon utility territories — would not take any service from the grid. They would be separated from the grid by redundant protective relays and other equipment that prevent them from ever taking energy off the grid or relying on other grid services.

“Exelon’s request should be rejected for what it is: another attempt by a monopoly utility to preserve and increase its market share at the expense of competition and economic development, including the critical and urgent national security need for artificial intelligence and data centers,” Constellation said.

Even with the clarification preserving netting arrangements, Constellation said Exelon’s rules are as “clear as mud.” The filings leave out details of the services the utilities would provide to “fully isolated co-located loads” and do not explain the rates it would charge them.

They would change the definition of network integration transmission service (NITS) in PJM and require every customer “synchronized” to the grid to become Exelon’s transmission customers, Constellation argued. “This would force office buildings, grocery stores and even homes across the Exelon footprint to become transmission customers under the PJM tariff.”

Exelon should have made the proposal under FPA Section 206 because only PJM itself can file changes to its rules under Section 205, Constellation said. Even if the changes were filed correctly, the lack of any description or justification of the rules means Exelon has failed to meet its burden of proof, it argued.

“Exelon wants to require its interconnection customers to be its transmission customers, but the commission has always recognized a distinction between the two services, and it should not allow Exelon to eliminate that distinction here through its control over interconnection services,” Constellation said. “Nor should the commission usurp a state’s authority to determine what is and is not a retail sale.”

Constellation filed affidavits with its protest from two experts: former PJM Vice President of Planning Steven Herling, and market design expert Roy Shanker.

Herling analyzed the engineering and equipment of co-located load and explained why the load is not relying on grid services.

“Protective relays prevent the load — be it data center, hydrogen electrolyzer or otherwise — from taking electricity off the grid,” he said. “Yet Exelon seeks to classify all fully isolated co-located load as network load. Basic engineering confirms that this load is not relying on the grid. Basic cost-causation principles dictate that this load should not pay for services it does not take.”

Herling said co-located loads have transformers to measure any flows between the grid, and the behind-the-fence customer can automatically trip circuit breakers if any such flows are detected. That can happen if the nuclear plant trips offline, or lower their output, unexpectedly and would “trip the load from the grid” in 0.05 seconds.

Exelon has protested an existing deal that Talen Energy wanted to expand with a data center at its Susquehanna Nuclear Plant. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)

The debate in the Talen proceeding led to FERC scheduling a technical conference on the issue for Nov. 1. The issues around data centers also are being taken up by state regulators, with the Virginia State Corporation Commission on Oct. 2 announcing a technical conference for December and the Maryland Public Service Commission recently holding a hearing. (See With Three Mile Island Restart, Debate Continues on Co-located Load in PJM.)

Data centers are particularly important to the modern economy, and their recent proliferation in Northern Virginia shows that only allowing them to connect through the grid can lead to significant delays, Constellation said.

While FERC has rules against generators withholding power, they can sell to any willing customer — including engaging in off-system bilateral sales.

“The commission cannot allow Exelon to exercise monopoly power or force all generators to live and die by RTO market prices,” Constellation said.

FERC has worked to correct “the excesses of transmission monopoly” through its 30 years of policies supporting open access, Constellation argued, while Exelon’s play is to quash a competitive alternative it believes threatens its bottom line. It is not just data centers; Constellation is using its LaSalle nuclear plant in Illinois to directly power hydrogen electrolyzers under the U.S. Department of Energy’s hydrogen hubs program.

The gross metering proposal would be a huge blow to that hydrogen effort, as well as to facilities such as batteries and pumped storage that withdraw more energy from the grid than they inject, Constellation said.

Other Parties Weigh in on the Issues

Exelon’s filing drew about a dozen responses from other stakeholders, with Advanced Energy United and the Solar Energy Industries Association urging the commission to either reject them or set them for hearing, so that the issues around co-location can be worked out in a general way.

“These new arrangements raise jurisdictional considerations that require a full analysis of implications based on the unique structure of the arrangement,” the organizations said. “The industry and the commission itself are still exploring the electrical, economic and legal implications of these arrangements.”

The lack of understanding around the issue could lead to unintended consequences if Exelon’s proposal were to go into effect before it is examined in a more general way such as at the technical conference next month, AEU and SEIA said.

Calpine also argued that the issue was too novel to be decided now and that Exelon’s proposal could impact industrial facilities and potentially even residential customers.

“The commission’s actions here will impact the nation’s ability to build vital data infrastructure that is critical for national security and economic development,” the company said. “This attempt to circumvent a policy discussion of national significance must be rejected.”

Old Dominion Electric Cooperative also wants to see FERC address the issues on a generic, or at least regional, basis — not ad hoc, transmission owner by transmission owner. The co-op uses behind-the-meter generation, including in Exelon’s territory, and it had urged the commission to reject the initial filing with its language about gross load because that could eliminate the longstanding netting of load it does for customers served by distributed generation.

“ODEC submits that such a piecemeal, TO-by-TO approach to these issues is inefficient and could lead to disparate treatment of co-located load and behind-the-meter generation throughout the PJM region,” the co-op said. “For [load-serving entities] like ODEC that have load in several PJM transmission zones, this disparate treatment can have real impacts on ODEC’s costs for transmission, ancillary service and PJM administrative charges, as well as ODEC’s ability to invest in generation resources and participate in demand response programs.”

Voltus, a virtual power plant provider, said that Exelon’s filings appear to be an attempt to get around FERC’s more general look at the issue with the November conference.

“Exelon provides no quantification of the size or number of facilities that are set to be built with the current tariff in effect, nor the timing of their construction,” Voltus said. “Without these details, Voltus does not understand Exelon’s need to move so expeditiously.”

Public Service Enterprise Group filed a protest arguing that Exelon’s proposal threatens New Jersey’s solar goals, saying it would harm the 90,000 BTM generation customers in its territory by making their service more expensive, and the same could be said for any qualifying facilities.

“The Exelon companies attempt to carve out from ‘all load’ BTMG, QFs and retail net metering arrangements,” PSEG said. “However, they make no effort to explain or justify why it is just and reasonable and not unduly discriminatory for co-located load to be treated differently than BTMG.”

PSEG also made the argument that while the filings claim to only apply to six Exelon utilities, they would modify general terms and conditions of PJM’s tariff, and Exelon lacks that authority. BTMG arrangements have been part of PJM’s rules for two decades, and Exelon’s proposals would threaten that activity, with the RTO’s tariff saying the load of a network customer “does not include the load served by operating” BTMG, PSEG argued.

“The central characteristic of a BTMG configuration is that it provides for the delivery of power from the generator to the co-located load ‘without using the transmission system,’” PSEG said.

The typical rooftop solar customer on PSEG’s system gets an annual bill of $59 from its service charge, but the firm estimated that under Exelon’s proposal, that would balloon to $419/year — a 700% increase. PSEG also estimated that it would impact several university campuses with BTMG by raising their network transmission charges by millions of dollars.

Exelon’s late revisions would carve out traditional BTMGs, but PSEG said that only compounds the filings’ legal flaws.

“As amended, the Exelon filings are unduly discriminatory and preferential in proposing fundamentally different treatment for BTMG arrangements, QFs and retail net metering arrangements on the one hand and co-located load arrangements on the other hand,” PSEG said.

Exelon’s proposal did win outright support from PJM’s Independent Market Monitor, who said in a filing that current proposals for co-located load would provide for “discriminatory treatment” for such customers and impose costs on other consumers.

“Such arrangements between generation owners and co-located loads are not private bilateral arrangements that can ignore the applicable requirements of the PJM” tariff, Monitoring Analytics said. “The core result for co-located load proposals is avoiding the costs assigned to transmission and distribution customers under both state and federal regulation.”

The deals would allow large co-located customers to avoid paying transmission and distribution charges, as well as any regulation by state commissions.

“The core assertion underlying such co-located arrangements, that a co-located load at a power plant can be isolated from the grid, is an illusion,” the Monitor said. “It is not possible to be off the grid. Both the power plant at which the co-located load is sited and the co-located load itself depend on the grid and cannot exist or function without the grid. In addition, the co-located load will continue to rely on the grid for a range of ancillary services including frequency control, reactive, spinning reserves, reserves in general, black start and PJM administrative functions.”

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Brattle Study Likely to Fuel Debate over EDAM, Markets+

A new white paper by The Brattle Group offers a point-by-point comparison of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ that leans in favor of EDAM but stops short of endorsing either market. 

The paper, published Oct. 1, likely will further fuel the ongoing and contentious debate between supporters of the two markets.  

It examines and compares seven design features in each market, including transmission optimization, fast-start pricing, real-time unit commitment (RTUC), procurement of imbalance and flexibility reserves, seams optimization, greenhouse gas pricing and congestion revenue allocation — all of which have been the subject of controversy between the two sides. 

“Many stakeholders in the [Western Interconnection] have suggested that certain market design elements, available in one market but not the other, will have material impacts on market outcomes and customer costs,” the paper says. “We aim to compare specific elements of the two market designs and, where possible, provide evidence that sheds light on where one market’s design is more likely to improve customer outcomes than the other.” 

Brattle produced the study on behalf of PacifiCorp, which in April became the first utility to sign an EDAM implementation agreement with CAISO. A separate Brattle study, released in September, found PacifiCorp could earn up to $359 million a year in net benefits from participating in the ISO’s day-ahead market, nearly double a previous estimate. (See Updated EDAM Study Shows Doubling of PacifiCorp Benefits.) 

“As we look at the future of the West and the next stage of market evolution, it’s clear that the logical next step is the EDAM,” Mike Wilding, vice president for energy supply management at PacifiCorp, said in a statement. “We have to strategically harness as much of the existing transmission and resource diversity of the West as we can, in order to benefit our customers, while maximizing the investments that will meet the evolving needs of the region into the future.” 

While resource diversity wasn’t a focus of the Oct. 1 analysis, the paper’s introduction emphasized Brattle’s finding from previous EDAM benefit studies performed for Western utilities: that the biggest driver of benefits in a day-ahead market will be creating the largest possible footprint containing the greatest diversity of load and resources — a point repeatedly argued by key EDAM supporters. 

“While some of the design differences between Markets+ and EDAM will impact market outcomes and overall market efficiency, they are unlikely to have a material effect on customer savings,” the paper says. “Various analyses of customer benefits from market participation indicate that the largest drivers of customer savings will be … the diversity of load and generation resources available in the markets, and the connectivity between participating members, which all lead to increased economic trading and lower curtailments in the market.” (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+ and NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

Flow-based vs. Contract Path

The core of the paper starts with an examination of a market feature that a core group of Markets+ funders addressed in their most recent “issue alert” covering market seams: transmission optimization. (See Markets+ ‘Equitable’ Solution to Seams Issues, Backers Say.) 

In their Sept. 17 alert, the Markets+ backers contend that, unlike the SPP market, EDAM doesn’t rely on a “full” flow-based approach for optimizing transmission use. 

“As a result, EDAM transfers between [balancing authority areas] and between [transmission service providers] will continue to be subject to contract-path scheduling limits used under the [open access transmission tariff] framework (and currently employed in WEIM [the Western Energy Imbalance Market]),” the alert says. 

The Brattle paper attempts to deconstruct that contention, arguing that both markets will be required to recognize contract path limitations because of “the complex nature of transmission rights” in the West, where the operation of transmission systems largely is decentralized because of the absence of an RTO. 

“This is consistent with both markets’ tariff language filed with the Federal Energy Regulatory Commission, which indicate that both markets plan to recognize contract-path transmission constraints where appropriate,” Brattle says, noting that FERC likely would have directed either market operator to include contract path constraints in their market-clearing processes if they’d proposed “purely” flow-based optimization. 

“Ignoring contract path rights in regional market clearing engines can result in commitment and dispatch decisions that create negative outcomes for neighboring entities,” Brattle writes. “For example, a market dispatch solution using a transmission asset beyond the contracted capacity can create congestion on the asset and impair the utilization of other parties’ transmission rights.” 

Brattle cited the controversy surrounding MISO’s integration of Entergy’s sprawling service territory (now MISO South) as a cautionary example of the consequences of ignoring contract path limitations in market dispatch. In that situation, MISO initially dispatched energy between its North and South regions without considering those limitations, which created parallel flows on neighboring systems and prompted SPP to “file a complaint with the FERC stating that ‘significant intentional, unscheduled incremental power flows are crossing SPP’s system without any corresponding reservation, service agreement or compensation.’” 

Western stakeholders concerned about the impact of contract path limitations would be best served by the entire region joining the same market, Brattle said. 

“This would bring all the physical transmission assets under the control of a single market operator, thereby reducing the need for contract path constraints. Moving towards a joint transmission tariff or a full regional transmission organization would further reduce, and possibly eliminate, the need for contract path constraints altogether,” the paper says. 

Fast-start Pricing

In another section, the Brattle paper plays down the importance of one market feature that Markets+ supporters have argued is an important benefit of the SPP market but notably absent from CAISO’s markets: fast-start pricing (FSP). 

“Some stakeholders have presented analyses suggesting that FSP has a substantial impact on market prices and revenues collected by generation resources that can come online quickly (‘fast-start resources’),” Brattle writes. “However, evidence from several U.S. markets, including SPP, indicates that FSP has a very minimal impact on market prices, impacts relatively few hours, and does not materially increase the market revenues of fast-start resources.” 

The paper points to discrete analyses performed by the market monitors for ISO-NE, MISO and SPP that showed “the overall frequency and magnitude of the price impacts of FSP [in each market] were very small.” 

For example, a MISO study covering 2016 showed FSP affected only 7.7% of real-time clearing intervals and increased real-time prices by just 1 cent/MWh, while an SPP study for 2022 found FSP increased fast-start resources’ day-ahead energy revenues by about 1.5% and real-time revenues by about 0.5%. 

Additionally, Brattle says, PJM’s Monitor “has also indicated that FSP potentially undermines the objective of reducing production cost, and its implementation in the PJM market has distorted efficiency.” 

Brattle also questioned the validity of a 2022 study conducted by consulting firm Energy GPS for Canada-based energy trader Powerex and the Portland, Ore.-based Public Power Council (both key Markets+ supporters). The study found that if CAISO markets had used FSP over 2017-2020, prices would have increased by $15 to $23/MWh and generators would have collected an additional $1.2 billion to $2 billion in market revenues. 

“The analysis informing [the Energy GPS] white paper calculated … fast-start units’ impacts on energy prices as the difference between the marginal cost of starting and running peaking units and the average energy price at regional pricing hubs (NP15 and SP15 in CAISO, plus the Southwest and Northwest regions),” Brattle said. “The study did not simulate a counterfactual market commitment and dispatch solution for the CAISO market to validate this impact, which falls short of the analytical rigor of the analysis conducted by the independent market monitors for the MISO, SPP and ISO-NE markets.” 

Jeff Spires, director of power at Powerex, said his “first impression” was that Brattle’s assessments of FSP was “flawed in multiple areas.” 

“Brattle mischaracterizes the methodology used by Energy GPS to assess the impact of fast-start pricing in the west and misrepresents the results of their analysis,” Spires told RTO Insider in an email, adding that the paper “selectively refers to certain historical data from eastern markets to support its conclusion, while failing to include other more recent metrics demonstrating a significant impact of fast-start pricing in eastern markets, including PJM and MISO.” 

Asked if he could supply those metrics, Spires said the Markets+ funders are compiling the information and will share it when it’s ready. 

Michael Linn, director of market analytics at the PPC, said the Brattle paper “misrepresents” the results of the Energy GPS study, and that the $15-$23/MWh range represented market prices “for the evening peak hours, typically the highest priced hours in the West when fast-start units are most often dispatched.” 

“The Brattle study takes these numbers and compares them to multi-month averages in other studies. The Energy GPS study included an apples-to-apples estimate of average fast-start price impacts that show prices increases by $2 to $4/MWh in Northern California, $4 to $9/MWh in Southern California over the study period, and lower impacts in the Pacific Northwest and Southwest,” Linn wrote. 

Linn said also that “while the Energy GPS study did not perform a counterfactual analysis, the study relied on publicly available data on actual historical fast-start unit dispatch and fuel costs, providing a useful and practical approach based on real-world data.” 

Linn criticized the Brattle report for “narrowly” focusing on “a few criticisms” of FSP and ignoring the “overwhelming evidence” of the benefits of the practice, “most recently echoed by the Western EIM Governing Body expert.” In May, that expert, Susan Pope, told the Western Energy Markets Governing Body that FSP could fix certain “price anomalies” in CAISO markets better than existing mechanisms for compensating fast-ramping resources. (See WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’.) 

‘Look Ahead’

The Brattle paper commends CAISO’s markets for using a market-clearing engine that relies on a four-hour “look ahead” period “that enables it to optimize real-time unit commitment decisions for generation resources in the market that can cycle on and off in four hours across the entire market footprint.” 

In contrast, Brattle says, the market-clearing engine that SPP uses for its Western Energy Imbalance Service (WEIS) does not include a similar look ahead or perform RTUC, and the Markets+ tariff doesn’t indicate that practice will be adopted in the newer market. 

“These additional features of the WEIM optimization will allow it to find lower-cost and more operationally responsive solutions relative to the Markets+ real-time clearing that will not perform unit commitment and relies on manual real-time unit commitment decisions,” the paper says. 

Brattle notes the look ahead feature provides an advantage only real-time optimization, but does not affect day-ahead operations, “where both EDAM and Markets+ optimize unit commitment and day-ahead dispatch.” 

In an email to RTO Insider, SPP spokesperson Meghan Sever said the WEIS design is “not relevant to a comparison of Markets+ and EDAM.” 

“WEIS is a separate service provided under a different tariff than Markets+,” Sever wrote. “The study assumes Markets+ will not include real-time unit commitment, although it is clearly defined in the Markets+ tariff filing currently being reviewed by FERC.” 

“We do not say that there is no real-time unit commitment, but rather that the real-time market clearing engine does not perform that function,” John Tsoukalis, a principal with Brattle and the report’s lead author, said in an email. 

Tsoukalis said the section of the Markets+ tariff that lists the outcomes of the “Real-Time Balancing Market” does not include unit commitment, while another section describes unit commitment as being an outcome of the reliability unit commitment process.

Markets+ Wins on Seams

The Brattle study also takes a more favorable view of EDAM’s GHG pricing mechanism, which it says benefits from 10 years of operational experience in CAISO and the WEIM, and the ISO’s process for allocating congestion revenues in its markets. 

But Brattle gives Markets+ higher marks for seams optimization, noting that the SPP market will require all participants along a market seam to offer buy and sell bids for import and exports at the seam — the practice of “intertie trading” — while in EDAM, intertie trading will only be activated if market members choose to do so and at the CAISO balancing authority area border. 

“The automatic inclusion of intertie trading at the Markets+ seam is likely to deliver benefits to market participants, and similar broad availability of intertie trading would be an improvement to the EDAM design,” Brattle wrote. 

‘Independent Evaluation,’ or ‘Limited’

Asked why PacifiCorp commissioned the study, spokesperson Omar Granados said the utility was seeking “to offer an independent evaluation of the market design, including the design differences between EDAM and Markets+. This information will be useful for potential future market enhancements and will help inform decision-making if the Western Energy Imbalance Market participants split their participation between two day-ahead markets.” 

For its part, Brattle said it hoped the paper provides “helpful takeaways for stakeholders in both markets on where the respective designs can be improved in the future, and help the region focus its efforts on developing the markets to enhance the overall efficiency and outcomes for customers.” 

CAISO and SPP offered predictably different takes on the study. 

“We appreciate Brattle’s publication of the comparative design paper between Markets+ and EDAM,” CAISO spokesperson Anne Gonzales told RTO Insider. “The assessment aligns with our perspective that EDAM provides significant reliability and economic value to customers across the West as designed, with the largest seamless footprint possible providing for significant load and resources diversity as well as transmission connectivity, all key factors in enabling those benefits.” 

SPP’s Sever said the RTO hadn’t been invited to participate in the study and was still reviewing the results. 

“Beyond our assessment of the study’s conclusions, SPP also notes that its scope is limited and ignores a number of factors that stand to distinguish it from other options. Production cost studies don’t tell the entire story,” she said. “Apart from the unique Markets+ design elements that will benefit all Western entities, participants will benefit from an independent and transparent governance and robust stakeholder process that values all participants equally.”