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November 5, 2024

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CAISO Releases Draft Interconnection Process Enhancements Proposal

CAISO on Feb. 8 released its final draft proposal out of its Interconnection Process Enhancements (IPE), its initiative to address the “unprecedented and unsustainable interconnection request volumes” submitted in the current and prior study windows. 

The draft refines the initial IPE straw proposal released Sept. 21, 2023. Among the changes are the development of a generic timeline expected to align with FERC Order 2023 requirements, tweaks to the implementation of the zonal approach and more detail on how to fulfill the 150% planned transmission capacity within each zone. 

“I just want to emphasize [that] the process we have right now is not working and will not get us to a reliable system,” Danielle Mills, principal of infrastructure policy development at CAISO, said at an IPE working group meeting Feb. 15. “So, we need fundamental change, and I know it’s a little scary, but we need to just all link arms and jump in together.” 

Mills emphasized that the IPE initiative is part of a broader set of changes designed to onboard new resources quickly and cost-effectively to meet California’s decarbonization goals. As part of the process, the ISO signed a joint memorandum of understanding with the California Public Utilities Commission and Energy Commission in December 2022 to establish a general direction. 

The goal of the initiative is to prioritize interconnection requests aligned with priority zones, called the “zonal approach,” where transmission capacity exists or is approved for development. Entities seeking to interconnect must go through a process in which they will receive a score based on project readiness that determines if they can enter the queue. 

Because of such high rates of interconnection requests (in 2023, Cluster 15 set a record at 541 requests), the ISO also asked for FERC approval to cancel the 2024 interconnection window to give it more time to study current requests, as well as to continue to refine the draft proposal. (See CAISO Seeks FERC’s OK to Shut 2024 Interconnection Window.) 

Data Transparency

In previous working group meetings, stakeholders emphasized the need for more information about where priority zones are located. 

In the draft proposal, the ISO identified that it would consolidate relevant information into a single document that provides line diagrams of interconnection areas and points of interconnection, identifies transmission constraints, and gives a list of substations within each zone and the transmission plan deliverability allocated for each constraint. 

Per Order 2023, heat maps will be available 30 days after a cluster study and 30 days after the restudy. The ISO is developing a heat map for Cluster 14, though it likely won’t be available 30 days after the cluster’s phase 2 reports are issued because Order 2023 applies to only Cluster 15 and beyond. 

Timeline Concerns

CAISO is seeking to implement its interconnection reforms — both its IPE proposal and Order 2023 compliance filing — at once.  

ISO staff plan to file the compliance proposal in April, though they are not sure when FERC will act upon it. Jeff Billinton, director of transmission infrastructure planning at the ISO, said because of that uncertainty, staff don’t expect to re-engage with Cluster 15 until the first half of 2025. Order 2023 compliance will have a negligible impact on clusters prior to 15, the IPE draft states. 

Stakeholders expressed concern over the intent to move forward with IPE changes while waiting on FERC’s approval, especially regarding site-control requirements. 

“There’s uncertainty about … your idea that there’s a certain timeline for re-engagement with Cluster 15,” said Jason Burwen, vice president of policy and strategy at GridStor. “Folks are going out to get site control, sign lease options and whatnot. As the timeline of uncertainty moves forward … folks are hanging on to land for even longer than they anticipated.” He asked if the ISO could make a definitive statement about site-control requirement timelines. 

Billinton responded that the timeline shouldn’t be too troublesome for entities seeking site control and interconnection in the Cluster 15 window. 

“The outermost deadline for having site control really is the commencement of the cluster study, which would be only, I don’t know, a few months after we re-engage with Cluster 15 and go through the validation process,” Billinton said. 

Chris Devon, director of energy market policy with Terra-Gen, asked if there was any chance FERC could move fast enough to expedite the timeline. 

“It is our intent to beg FERC for an order as fast as possible,” Billinton said. 

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FERC Rejects Pump Storage Projects Over Navajo Objections

FERC on Feb. 15 rejected preliminary permits for seven pump storage projects on Navajo Nation land, saying it will no longer consider projects that are opposed by host tribes. 

Preliminary permits give the permit holder priority for filing a development application while it conducts feasibility studies. It does not authorize access to project lands or any construction. 

The commission previously granted preliminary permits routinely, saying concerns about potential impacts could be addressed in subsequent licensing proceedings. Recently, however, it denied permits at federal facilities where the agency that operates the facility opposed the project. 

“We believe that our trust responsibility to tribes counsels a similar policy in cases involving tribal lands and accordingly, we are establishing a new policy that the commission will not issue preliminary permits for projects proposing to use tribal lands if the tribe on whose lands the project is to be located opposes the permit,” FERC said. “To avoid permit denials, potential applicants should work closely with tribal stakeholders prior to filing applications to ensure that tribes are fully informed about proposed projects on their lands and to determine whether they are willing to consider the project development.” 

Denied were five preliminary permit applications filed by Nature and People First Arizona PHS LLC (NPFA):  

    • the 2,250-MW Black Mesa Pumped Storage Project North; the 1,500-MW Black Mesa Pumped Storage Project East; and the 2,250-MW Black Mesa Pumped Storage Project South, all closed-loop systems on Navajo Nation land in Navajo and Apache counties, Ariz. (P-15233, P-15234, P-15235); 
    • the Chuska Mountain Pumped Storage Project, proposed for San Juan and McKinley counties, N.M. (P-15293-001); and 
    • the Chuska Mountain North Pumped Storage Project in Apache County, Ariz. (P-15309). 

FERC also rejected Western Navajo Pumped Storage’s proposed Western Pumped Storage 1 and Western Pumped Storage 2 in Coconino County, Ariz. (P-15314, P-15315) 

In contrast, the commission awarded preliminary permits Feb. 15 to Neptune Pumped Storage for feasibility studies of the 318-MW Elephant Rock Pumped Storage Project near Sixes River (P-15310) and the 550-MW Soldier Camp Pumped Storage Project on Lobster Creek (P-15311), both in Curry County, Ore. 

The commission approved the permits, which are good for 48 months, despite protests from environmental groups that cited concerns over the projects’ impact on water quality and quantity, aquatic resources, wildlife and habitats, and tribal resources. Some opponents said it was doubtful the state of Oregon would issue water quality certifications for the projects. 

But FERC ruled that because a preliminary permit does not authorize access to project lands or project construction, “addressing the commenters’ concerns at the permit stage is premature.” 

FERC said it sent 12 tribes identified by Neptune Pumped Storage as having a potential interest in the Soldier Camp project a copy of the notice accepting the application but none of the tribes filed comments. 

The Navajo Nation raised numerous objections to the projects proposed on its lands, including that developers had not sought its consent for use of the land or procured required clearances for preliminary biological investigations. The Nation also cited concerns over its water rights and potential impacts on rare and culturally important plants and wildlife and said the developers had failed to engage in “meaningful consultation.” 

| Navajo Land Department

The Navajo Tribal Utility Authority, a unit of the nation that provides electric generation, transmission and distribution, did not take a position on NPFA’s Black Mesa projects but said it “looks forward to robust cooperation, communication and transparency” as the developer pursued its application. 

“Despite substantial progress in recent years, thousands of homes on the Navajo Nation still lack access to electricity and other basic services,” the authority told FERC in January 2023. “Accordingly, NTUA recognizes the wide range of benefits that can flow from environmentally, economically and culturally responsible energy development on and around Navajo land, including the creation of well-paying, local jobs for Navajo residents.”  

In addition to its new policy, FERC’s acknowledgment of tribal concerns was reflected in the Office of Public Participation’s annual report, issued Feb. 15, which noted its participation in the Tribal Energy Equity Summit, “Just Transmission for a Just Transition” in Saint Paul, Minn. in May 2023. (See related story, FERC Meets at Howard Law School and Gets Update on OPP Activity.)

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FERC Finalizes Winter Reliability Standards from 2021’s Uri

WASHINGTON — FERC has approved new mandatory reliability standards on weatherization that implement recommendations that came out of its and NERC’s joint report on the 2021 outages caused by Winter Storm Uri. 

The outages caused by cold weather that week were worst in Texas, though other grids suffered shorter outages. Overall, 4.5 million people lost power and 210 people died during the storm. 

NERC adopted a two-phase process to implement recommendations from the FERC/NERC joint report on Uri, and FERC’s order Feb. 15 deals with the second phase. 

The EOP-011-04 standard requires utilities to include critical natural gas infrastructure on their load-shedding plans so they are not shut down due to a lack of power, exacerbating electric outages during cold weather, as happened in Texas. Balancing authorities must develop, maintain and implement operating plans with provisions for excluding critical gas infrastructure from interruptible load, curtailable load and demand response during cold weather. 

NERC also sought approval of standard TOP-002-5, which requires balancing authorities to have an operating process for weather events that includes a method for identifying extreme cold conditions, a method for determining a proper reserve margin for such conditions that takes into account operational limits of generators and a method for determining a five-day hourly forecast that accounts for all relevant operational considerations. 

FERC said ensuring natural gas infrastructure works during cold weather is an improvement over current rules. 

“Doing so will help ensure that deploying these programs in extreme cold weather conditions will not exacerbate natural gas fuel supply issues, which could constrain generating unit capacity and thereby threaten the reliable operation of the bulk power system,” FERC said. 

The proposal gives distribution and transmission providers 30 months to develop a plan, with the clock starting later this year. That led FERC in its order, and commissioners at their regular open meeting, to ask entities that can do so to comply earlier. 

“Utilities that can comply early with the mandatory implementation date, please, I implore you: Do so,” Chair Willie Phillips said.  

Commissioner Allison Clements seconded the call at the open meeting and in a concurrence to the order, noting some of the improvements are not required to be in place until more than three years from now. 

“The grid and customers won’t experience the full extent of these protections for at least three more winters,” Clements said. “I appreciate that NERC has worked hard to improve reliability standards and that the implementation timeline here is responsive to some concerns in the stakeholder process, which is important. But as I’ve stated at past open meetings, waiting years for new reliability standards to kick in, whether they be cold weather or cybersecurity requirements, is not reflective of the urgency these issues demand.” 

The industry has seen other cold winter events since Uri, with NERC and FERC working on another joint report from the cold weather experienced in January. 

FERC Delegates Settlement Authority to Enforcement Director

FERC also issued a policy statement tweaking how it handles enforcement actions that delegates authority to open settlement talks with subjects of investigations to the director of the Office of Enforcement. Previously, staff had to get permission from FERC commissioners themselves to take that step. 

The change is meant to streamline the settlement process so enforcement investigations are resolved more efficiently. 

“If and when enforcement staff receives a viable settlement offer from the subject, it will negotiate the applicable terms and thereafter present the written offer of settlement to the commission for formal voting,” FERC said in its policy statement. “Importantly, while the new process grants enforcement staff new discretion to commence and engage in settlement negotiations, it does not change the fact that it is the commission that ultimately determines whether a settlement of an investigation is in the public interest and should be approved.”

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Enviros, Consumer Advocates Join Regulators Urging PJM-MISO Interregional Planning

A bevy of consumer, clean energy and environmental advocates have joined state regulators in appealing to MISO and PJM to undertake more comprehensive interregional transmission planning.  

Clean energy groups and consumer advocates have banded together to send separate letters to MISO and PJM’s Interregional Planning Stakeholder Advisory Committee (IPSAC) to request a new approach to interregional planning.  

A collection of 13 environmental groups said there’s an urgent need for more transmission bridging MISO and PJM “from a reliability, economic and public policy perspective.” The letter was penned by the Rocky Mountain Institute and signed by the Union of Concerned Scientists, Advanced Energy United, Clean Grid Alliance, Sierra Club, Environmental Law and Policy Center, Natural Resources Defense Council, Americans for a Clean Energy Grid and Earthjustice, among others.  

“Despite the continued demonstration of need for enhanced interregional transmission between PJM and MISO, total buildout of interregional transmission continues to lag this demonstrated need,” the organizations said.  

Consumer advocates, including Michigan’s and Illinois’ attorneys general; the Citizens Utility Boards of Michigan, Illinois and Minnesota; the Indiana Office of Utility Consumer Counselor; and the New Jersey Division of Rate Counsel struck a similar tone in their letter. 

“Transmission planning is more cost effective and results in better outcomes for consumers when it is done comprehensively, transparently, and using multivalue drivers. The current siloed process forces ratepayers to pay more for less beneficial outcomes,” the offices wrote. They said MISO and PJM don’t have a process to “proactively plan and build large-scale transmission” across their seams.  

“The processes that do exist are reactive, difficult to navigate and small scale,” the offices added.  

The groups’ appeal to the RTOs’ IPSAC coincides with a similar letter from the Organization of MISO States (OMS) and the Organization of PJM States Inc. (OPSI), which also asked MISO and PJM to redouble efforts around interregional planning. (See OMS, OPSI Urge MISO, PJM to Invigorate Interregional Planning.) MISO and PJM are conducting an annual issues review to determine the need for a joint transmission study this year.  

Both the consumer and clean energy advocates said the RTOs could use a proactive, forward-looking approach to plan interregional projects, rather than the historical view of their system that they have relied on to pinpoint needs. The clean energy organizations said MISO and PJM would benefit from a standardized set of benefit metrics, shared system modeling and a more comprehensive view of project needs that merges reliability, economics and public policy instead of considering them one at a time in studies. 

Today, MISO’s and PJM’s planning limitations “result in minimal transmission buildout, higher costs for consumers, and a less reliable and resilient grid,” the clean energy groups said. They recommended MISO and PJM incorporate their members’ plans and generation expansion predictions into a long-range-style planning process that looks ahead about 20 years.  

“Given the demonstrated, and accelerating, need for more interregional transmission between PJM and MISO, we request that the IPSAC initiate a more proactive, comprehensive interregional transmission planning process than what is currently done today,” they wrote to MISO and PJM. They asked the IPSAC to host a series of stakeholder discussions or create a working group to design a revamped   planning process that can be kicked off with a study within one or two years.  

“Failure to do so will continue to commit ratepayers in PJM and MISO to overpaying for inefficient, balkanized regional solutions that do not take into consideration the billions of dollars in benefits from enhancing interregional transmission between the two RTOs,” they stated.  

Rocky Mountain Institute’s Claire Wayner said while MISO and SPP have been actively planning for their seam through the Joint Targeted Interconnection Queue, MISO’s and PJM’s seam has been overlooked.  

“There hasn’t been much, really nothing at the scale we need to enhance grid reliability and reduce costs for customers and further clean energy,” Wayner said in an interview with RTO Insider.  

Wayner said she suspects there aren’t enough resources dedicated to MISO-PJM interregional planning and that the grid operators are employing a “wait and see mentality” on FERC’s potential minimum requirement for interregional transfer capability. She said she was “thrilled” to see OMS and OPSI’s nudge by way of their joint letter. Wayner said she thinks MISO and PJM members are missing an opportunity to secure federal money for new interregional linkages through the Infrastructure Investment and Jobs Act.  

Wayner said new MISO-PJM lines could bring not only new generation onto the grid and relieve interconnection queues but also aid progress toward clean energy goals in states like Michigan and Illinois, which straddle MISO and PJM and have aggressive clean energy goals.  

“I think there’s a disconnect between what planning MISO and PJM are doing by way of their coordinated system plan and the IPSAC and what all of these least-cost decarbonization models are showing us we need,” she said.  

Beyond decarbonization, Wayner said stronger connections will help maintain reliability during increasingly severe weather events. She said there’s growing research showing that the nation will need “major, lateral transfers of power.”  

Wayner said she thinks MISO and PJM should reassess their existing coordinated system plan and Targeted Market Efficiency Project process and put in place a planning process that looks 20 years ahead and simultaneously considers multiple benefits. She said she’s “not impressed by the scope or scale of planning that’s happened between MISO and PJM to date” and said much of that planning appears to be motivated by Northern Indiana Public Service Co.’s 2013 complaint against MISO and PJM’s interregional efforts. She said MISO’s and PJM’s sole interregional market efficiency project and four batches of small TMEPs are “not the type of transmission that we need to build the grid of the future.”  

“We’re telling them, you need to reinvent your framework because it’s siloed and it’s not working,” she said.  

MISO and PJM are set to address regulators, consumer advocates and clean energy groups’ ask for better interregional planning at the March 1 IPSAC teleconference.  

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NERC Board of Trustees/MRC Briefs: Feb. 14-15, 2024

HOUSTON — NERC Board Chair Ken DeFontes will hold the gavel for one more year after the organization’s Board of Trustees re-elected him at its quarterly open meeting Feb. 15. 

The board chose Suzanne Keenan as vice chair and chair-elect, replacing current vice chair George Hawkins. Hawkins will continue to serve on the board, along with fellow trustees Larry Irving, Sue Kelly and Rob Manning, all of whom were elected to new three-year terms at the Feb. 14 open meeting of the ERO’s Member Representatives Committee. 

NERC to Leave Atlanta Office

NERC CEO Jim Robb reported in his opening remarks that the organization has opted not to renew the lease on its Atlanta office when it expires in 2025. Citing positive industry responses to the ERO’s renovated office in Washington, Robb said NERC will step up its use of that space and of regional entities’ facilities. While NERC will continue to hold meetings and events in Atlanta, Robb said it is in talks to use a local coworking space. 

NERC’s next board and MRC meetings will be at the Washington office in May, following a hybrid format in which only trustees and MRC participants attend in person and observers join remotely. 

Cold Weather Standard Accepted

As the board voted on the new reliability standard EOP-012-2 (Extreme cold weather preparedness and operations), DeFontes applauded “the hard work on the part of the entire industry” that brought the standard to this point. 

EOP-012-2 has been in development since February 2023, when FERC approved its predecessor EOP-012-1 with orders to NERC to draft a new standard within a year addressing its shortcomings. Getting the project to completion proved challenging, however. Industry stakeholders rejected the proposed standard in multiple ballot rounds, raising concerns among NERC’s leadership that FERC’s deadline might be missed. 

The impasse reached a peak at the board’s last meeting in December, when DeFontes warned that the board might exercise its authority under Section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot. But this proved unnecessary after stakeholders approved the standard at its third ballot round in January with an 81% segment-weighted vote for passage. (See Industry Approves New Cold Weather Standard in Final Vote.) 

Along with the cold weather standard, the board also agreed to submit for FERC approval a new set of definitions for NERC’s glossary affecting multiple standards. The terms are the result of Project 2022-01 (Reporting ACE definition and associated terms) and were approved in an industry ballot that concluded Dec. 20. 

Soo Jin Kim, NERC’s vice president of engineering and standards, told trustees the project was started because the Eastern Interconnection was “experiencing more frequent events with regard to area control errors (ACE)” compared to the Western Interconnection. 

The Reliability and Security Technical Committee’s Resources Subcommittee determined the current definition of Reporting ACE in NERC’s glossary did not allow the Eastern Interconnection to implement automatic time error correction processes. Kim said the changes will allow all interconnections to use time error correction and clarify what information should be used in calculating Reporting ACE. 

Stakeholders Discuss ROP Changes

According to the agenda, trustees would have voted on proposed changes to NERC’s Rules of Procedure relating to registration of inverter-based resources after the standards actions. But DeFontes informed attendees that because of stakeholder feedback regarding this item, the board decided to host a discussion of the proposal instead. He said the discussion will inform the board’s vote on the measure “a week or two from now.” 

NERC developed the proposed ROP changes last year as Stage 1 of its three-stage registration process, which FERC approved in May 2023 (RD22-4). They mainly will update the definitions of generator owner and operator to include entities with IBRs connected to the grid. 

Howard Gugel, NERC’s vice president for compliance assurance and registration, opened the conversation by highlighting a “minor victory” in the fact that “everyone in here agrees [about] who needs to be registered,” citing widespread agreement on the proposal that entities operating IBRs with aggregate nameplate capacity of at least 20 MVA, working through a common point of connection with a voltage of at least 60 kV, should be considered part of the bulk electric system and subject to NERC standards. 

However, he also acknowledged the concerns of many stakeholders that the proposed definition would be overly broad and disruptive to their businesses. Exelon’s Jennifer Sterling, for example, said many worried the proposed definitions would affect enforcement of standards and apply to utilities that they were not intended to. 

“Being the engineer that I am, I was concentrating on the numbers and focused on that victory, and not realizing that there were some other key conversations that really needed to occur,” Gugel said. 

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NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds

New Jersey’s Board of Public Utilities shut down its third offering of nuclear subsidies after PSEG Nuclear and Constellation Energy Generation, which operate the state’s three nuclear plants, opted to not apply for state subsidies as they seek federal support. 

The board’s unanimous vote Feb. 14 quietly ended a process to determine support for the three South Jersey nuclear plants — Hope Creek, Salem 1 and Salem 2 — that in the last subsidy process triggered a contentious debate over whether the plants needed the financial break to remain in existence. 

The Zero Emission Certificate (ZEC) program provides subsidies to nuclear power plants at risk of closure so they can remain open to generate carbon-free power. A ZEC in New Jersey compensates the nuclear plant for generating one megawatt-hour of electricity, with funds collected by the utilities from ratepayers at a rate of $0.004 per kilowatt hour (kWh). 

In the 2022 discussions to decide subsidies for the current three-year period, which covers 2023 to 2025, critics argued that the plant operators did not need the maximum possible subsidy of $300 million to remain in business. The BPU, which under the law could have reduced the amount, nevertheless awarded the maximum. 

The BPU said in the Feb. 14 order that the third offering, which the board opened Aug. 21, would be closed because there were no applications once PSEG and Constellation withdrew. The offering would have awarded subsidies from June 2025 to May 2028. 

Doug O’Malley, director of Environment New Jersey, called the move a “win for ratepayers” that means the funds that might have gone to the nuclear plants in the future now can support other forms of clean energy generation. 

“We do need to obviously move towards an energy future that isn’t necessarily dependent upon” aging nuclear plants, he said. 

Maintaining Options

PSEG — the sole owner and operator of the Hope Creek plant and the operator and majority co-owner of Salem 1 and Salem 2 plants — submitted a notice of intent Aug. 21 to file for ZECs for the three plants. So did Constellation Energy, the minority co-owner. 

But both companies withdrew from the ZEC process. In a Nov. 22, 2023, letter to the board, PSEG said its earlier notice of intent was “filed to preserve PSEG’s rights” while it pursued federal production tax credits (PTC) due to be awarded to nuclear power generators under the 2022 Inflation Reduction Act. 

PTCs create a credit of $15/mWh for electricity produced by existing nuclear plants, beginning at the start of 2024 and running through 2032, according to the Nuclear Energy Institute. New Jersey paid $10/MWh in its two awards. 

PSEG said the federal program would “impact” the state ZEC program, and at the time the utility filed the notice of intent, it was awaiting “further clarity” from the Treasury Department of final rules regarding implementation of the PTC. 

“While those rules have still not been issued, PSEG has determined in light of all relevant facts and circumstances, including the purpose of the PTC established by Congress for qualifying nuclear facilities, that at this time the company does not intend to file applications in this (New Jersey’s) proceeding with respect to its three nuclear generation units,” the letter said. 

Constellation submitted a similar letter to the BPU on Nov. 30. 

PSEG released a statement Feb. 15 saying that though the Treasury rules for the PTC program still have not been issued, the company “has confidence that the PTC will proceed as intended and sufficiently support the nuclear generating units.” 

The statement added that the company remains committed to “providing carbon-free, reliable and affordable sources of power generation and will revisit the need for ZECs if federal support of the industry is insufficient.” 

Former CEO Ralph Izzo, who stepped down in 2022, suggested at least twice before he left that the company was looking to the federal government for support for the nuclear plants, adding in May 2022 that it would “reduce the pressure on New Jersey customers.” (See PSEG Sees Potential $3B OSW Transmission Spending.) 

Net-Zero Reliance

Nuclear-generated electricity accounts for about 35% of the state’s power at present, with solar power contributing 7%. The state has no wind power yet online. State officials and environmental groups say maintaining the nuclear plants’ operations will be key to helping the state achieve the goal set by Gov. Phil Murphy (D) of 100% clean energy by 2035. 

The Legislature created the program in 2018, and the board in 2019 awarded ZECs totaling $300 million to the three South Jersey nuclear plants in the first award under the law. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.) 

In the next award in 2022, covering the period from June 2023 to May 2025, state law allowed the BPU to set the size of the award. But PSEG said in discussions leading to the award that it would close the plants unless it received the $10/MWh rate, which is the maximum the program allows and the amount the BPU awarded. 

That sparked criticism from the New Jersey Division of Rate Counsel, the state’s consumer advocate, and environmental activists, some of whom said PSEG had exploited its market dominance to extract an unnecessarily large payoff. Some BPU commissioners also expressed concern at the size of the award but said the environmental and financial cost of not awarding the ZECs would be too great. (See New Jersey Nukes Awarded $300 Million in ZECs.) 

Rate Counsel Opposition

After the award, the Division of Rate Counsel filed an appeal of the awards to the Appellate Division of the state Superior Court, which rejected the claim in a Dec. 4 ruling.  

The rate counsel argued the BPU failed to do a thorough review of the case and disregarded “expert opinion that the three plants miscalculated their revenues, costs and risks, whereas a correct accounting demonstrated the plants did not need subsidization.” The Appellate Division concluded the board’s findings that underpinned the award were supported by “substantial evidence.” 

Brian O. Lipman, director for the Division of Rate Counsel, welcomed the closure of the ZEC process for another three years. 

“It’ll be good news for ratepayers, especially the commercial/industrial in the state because this was a major impact on their bill,” he said, and reiterated the belief expressed in the court arguments that the plants did not need subsidies to survive. 

“I do think that to the extent subsidies are needed, this is more of a federal issue, which should be dealt with at the federal level,” he said. “Ratepayers should not be paying subsidies for nuclear power plants in New Jersey.” 

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State Regulators Debate Reliability and Transmission at House Hearing

House members and their state regulator witnesses split Feb. 14 over how much an expanded transmission grid could enable a reliable transition to a low-carbon future.  

“Threats to electric grid reliability are growing due to environmental regulations, policies from state legislatures and agencies, bans on fossil fuel generation, and market distortions,” said Rep. Jeff Duncan (R-S.C.), chair of the House Committee on Energy & Commerce’s Subcommittee on Energy, Climate and Grid Security. “These factors are contributing to premature retirement for most of our reliable and dispatchable resources. Because of the increasingly interconnected nature of the grid, policy decisions that affect grid reliability have a much wider impact than ever before.” 

Rep. Scott Peters (D-Calif.), who also sits on the subcommittee, has introduced legislation to help address some of those reliability concerns by requiring minimum transfer levels between regions. (See Hickenlooper and Peters Introduce Big WIRES Act.) He agreed with Republicans on the committee that policymakers need to address resource adequacy with growing demand from electrification, data centers and new industries. 

“Multiple analyses recently from MIT and Columbia have shown that the Big Wires Act, which I and Senator Hickenlooper introduced, would save customers hundreds of millions of dollars while keeping the lights on during natural disasters and other challenges,” Peters said. “These costs and reliability benefits are driven by the ability of high-demand regions to use energy from other regions that don’t need it at that time.” 

Duncan doubted that increased transmission could be a cure-all for the country’s reliability woes, calling instead for maintenance ofexisting dispatchable generation. 

“Systems must be overbuilt to ensure there’s power when the sun is down and when the wind isn’t blowing,” Duncan said. “Building more transmission also raises utility costs for American ratepayers, even if those ratepayers may not directly benefit from the added transmission.” 

California and New England have adopted similar policies driving their grids to zero out emissions, but both rely on imports from other areas, and both have some of the highest electricity prices in the country, Duncan added. 

Georgia Public Service Commissioner Tricia Pridemore touted the reliability of her state’s vertically integrated structure.  

“Georgia is in need of more power than ever before,” she said. “Our market structure makes us more energy-secure than other regions; we have the authority to instruct utilities to construct generation and build transmission. The state of Georgia holds a compact with a vertically integrated utility, and they must generate what our state consumes.” 

While the Vogtle nuclear plant’s cost overruns might have made a lot of headlines and increased her consumers’ bills, she said that the Peach State still has rates 10% below the national average.  

Peters asked Pridemore whether Georgia would exclusively rely on its own power plants, given that it is connected to five other regions of the Eastern Interconnection. 

While Georgia is connected, the regulatory compact the state has with Southern Co.’s Georgia Power requires it to produce all of the power the state needs, she said. 

“You mentioned blackouts and forced outages earlier,” Pridemore said. “You can look at the last three winter storm incidents, and the number of blackouts and outages that we had were so minimal. They were just those that were caused by downed trees and localized events.” 

Pridemore called for easing regulation of pipelines, and Peters asked whether she thought that effort should be extended to transmission. Pridemore answered that she is “satisfied” with how Georgia manages electric transmission. 

Colorado, the only state with a carbon policy at the hearing, was represented by Keith Hay, senior director of policy in the state Energy Office, who said the state’s goals are not too difficult to achieve with the resources it can access. 

“Our modeling shows that under the business-as-usual approach, which is the lowest-cost scenario that meets a 2040 load growth of 40%, the Colorado grid can achieve a roughly 94% reduction in greenhouse gas pollution,” Hay said. “It does this by adding significant amounts of wind, solar and batteries while retaining a gas generation fleet that is approximately the size of today’s.” 

While the gas plants will still be there, their capacity factors would drop significantly over time according to the model: By 2030, only one natural gas unit approaches a 20% capacity factor, and by 2040, natural gas will produce just 2% of the state’s electricity, he added. 

“The analysis strongly indicates that expanded transmission capacity, both in-state and interregional, which will enable reaching regions of high renewable potential and allowing access to energy from across diverse geographic areas, will be important to reliably meeting Colorado’s electric needs,” Hay said. 

Indiana has seen coal fall from 90-95% of its electricity 20 years ago to about 45% today, with the rest coming from natural gas, nuclear, wind, solar and other fuels, said Utility Regulatory Commission Chair Jim Huston. While Colorado has found no major issues in moving to a net zero future, Indiana has said it would face difficulty meeting the requirements of EPA’s power plant rule.  

“Our concerns included a focus on the proposed rules’ unrealistic timing, particularly in the context of the utilities’ state-sanctioned and regulator-reviewed integrated resource plans,” Huston said. “It is not obvious that the proposed environmental benefits outweigh the other pillar considerations that state regulators must consider to ensure safe, reliable service at affordable rates.” 

Arizona also has seen cost issues from shutting down fossil fuel-fired plants early, said Corporation Commissioner Nick Myers. 

“Many of the challenges we face moving forward with regard to reliable generation center around early forced retirement of coal plants without adequate replacement,” Myers said. “Personally, it pains me to have to approve accelerated cost recovery for early shutdown of coal plants, while at the same time authorizing recovery on new purchase power agreements.” 

The replacement generation usually has to come with backup natural gas and transmission, which Myers said makes its all-in costs higher. The transmission also presents its own roadblocks, as Arizona had to deal with multiple iterations of the SunZia Transmission project and its 16-year development journey, marred by lawsuits and red tape. (See SunZia Project Wins Final Approval, Signs Offtakers.) 

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Caltrans Signs $127M Deal for Hydrogen-powered Trains

California is spending $127 million to buy six hydrogen-powered passenger trains, building on an earlier order of four of the zero-emission vehicles from Stadler Rail.

The California Department of Transportation (Caltrans) announced the latest purchase Feb. 14. It is a follow-up to the $80 million contract with Stadler Rail, signed in October, for four hydrogen-powered passenger trains.

The contract includes options for up to 25 additional hydrogen trains on top of the first four.

The first trains are expected to start paid service in 2027. They will run mainly between Merced and Sacramento but may also be used in demonstrations across the state.

“California continues to lead the way to a cleaner, more connected transportation system,” California Transportation Secretary Toks Omishakin said in a statement. ‘By expanding our fleet of hydrogen-powered passenger train sets, we are showing we are serious about deploying innovative and sustainable transportation options for the people of this state.”

Omishakin said previously that the hydrogen trains will complement California’s future electrified high-speed rail line. The first hydrogen trains will run along an expansion of the existing Altamont Corridor Express (ACE) and Amtrak San Joaquin routes that will eventually connect with high-speed rail between Merced and Bakersfield.

Funding for the hydrogen trains is coming from Gov. Gavin Newsom’s $10 billion zero-emission vehicle package. The multiyear package includes $407 million for the California State Transportation Agency to buy or lease clean bus and rail equipment and infrastructure.

The multicar trains from Stadler will use hydrogen fuel cells and won’t need a locomotive.

The design, which Stadler calls the Fast Light Intercity and Regional Train (FLIRT), makes the trains lighter, less expensive and more efficient than traditional locomotive-hauled coaches, Caltrans said.

Stadler initially worked with the San Bernardino County Transportation Authority (SBCTA) on developing the hydrogen-powered trains. That work led to Caltrans’ purchase in October of what the agency called the first zero-emission, hydrogen intercity passenger trains in North America.

Stadler is a Swiss company with a U.S. division based in Salt Lake City. Stadler said the new hydrogen train has been tested extensively in the U.S. and Switzerland.

Caltrans’ purchase agreement with Stadler in October came just before the U.S. Department of Energy announced that California will receive up to $1.2 billion as one of the nation’s seven potential regional hydrogen hubs. (See DOE Designates Seven Regional Hydrogen Hubs.)

Among the goals of the California hub are to decarbonize public transportation, heavy-duty trucking and port operations.

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NEPOOL Reliability Committee Briefs: Feb. 14

ISO-NE provided additional detail in response to stakeholder questions about how the RTO plans to model oil and gas resources as part of its ongoing Resource Capacity Accreditation (RCA) project at the NEPOOL Reliability Committee (RC) on Feb. 14.

The RTO explained the Resource Adequacy Assessment (RAA) modeling approach to the RC in January. (See ISO-NE Details Resource Modeling Plans for Capacity Accreditation.) Stakeholders followed up with feedback related to the modeling of imports from Saint John LNG, the uncertain future of the Everett Marine Terminal (EMT) and variability in the amount of gas available to generators.

Fei Zeng of ISO-NE said the current modeling approach “accounts for the EMT impact in a balanced way, given its uncertain future status. The adjustments made to historical availability to generation do not contemplate a single scenario of EMT either continuing operation or retired; therefore, fewer additional adjustments will be needed when EMT status becomes known.”

If EMT is not retained, ISO-NE will adjust its modeling to consider how the loss would impact local gas distribution companies, and the knock-on effects this would have on gas available for generators, Zeng said. If EMT is retained, ISO-NE will assess how much “additional available gas to generation EMT can provide through the remaining capacity headroom” on the region’s major gas pipelines.

Massachusetts’ two largest gas utilities recently announced agreements with Constellation, the owner of EMT, to keep the facility open through May of 2030, pending approval of the Massachusetts Department of Public Utilities. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.)

In response to feedback that the modeling approach “assumes higher LNG imports from Saint John than have been observed historically,” Zeng said the modeling approach is intended to calculate how much nonfirm gas is available when gas utility demand is accounted for, and modeling “unavailability due to economic reasons for the future is very difficult to predict and is generally not considered in the resource modeling.”

Regarding concerns about whether the modeling will adequately capture variability associated with extreme temperatures, Zeng said ISO-NE thinks the approach “reasonably reflects the gas fleet availability under different temperature conditions,” adding that the RTO “is open to further evaluating the inclusion of variability in the gas profile modeling as a future enhancement.”

Zeng also discussed how the RCA changes will affect how ISO-NE models the load profile in RAA. The load shape is currently built “by scaling the 2002 hourly load shape to reflect the forecasted seasonal ‘gross’ peaks.”

ISO-NE is planning to switch to “a composite seasonal load shape that is based on the 2021 annual net load characteristics and reflecting 2021 hourly weather for [April through September] and the 2013/14 hourly weather” for October through March.

Zeng noted that the 2002 load shape does not capture recent changes stemming from energy efficiency gains and behind-the-meter solar. He said the updates would better align ISO-NE with the methodology used in NPCC seasonal assessments.

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Eversource Finds OSW Buyer, Takes $1.95B Hit for 2023

Eversource Energy has finalized its long-running attempt to sell off its offshore wind assets, but not soon enough to avoid a $1.95 billion impairment for 2023. 

If the moving pieces come together as planned, the New England utility will be done with the struggling offshore wind sector, though it will continue to lead onshore transmission infrastructure work for the projects underway in its joint venture with Ørsted. 

Eversource announced the sale to Global Infrastructure Partners (GIP) after the financial markets closed Feb. 13, along with its fourth-quarter and full-year financials. Its stock, which has been trading near a five-year low, closed 4.7% higher in heavier-than-average trading Feb. 14. 

Eversource also said it will begin to evaluate market interest for Aquarion Water, the sale of which would bring an infusion of cash without resorting to the equity market. 

The sale of the offshore wind interests and the water utility would refocus the company on natural gas and electric transmission and distribution, which now provide the vast majority of its earnings. 

The Ørsted-Eversource venture has not been a failure: The partners expect to finish the nation’s first utility-scale offshore wind farm — South Fork Wind — next month, have begun construction of Revolution Wind and are far along in planning for Sunrise Wind. But the effort has been much more costly than expected, causing billions in losses for both.  

Ørsted, the world’s leading offshore developer, is pushing forward with some cutbacks. (See Ørsted Exits Offshore Wind Markets, Remains Committed to US.) But Eversource, New England’s largest electric utility, decided over a year ago to jettison what was becoming an albatross around its neck. 

Piece by piece, it has made progress. Ørsted bought Eversource’s share of their as-yet-undeveloped seabed leases, and it agreed to buy Eversource’s share of Sunrise if New York state awards Sunrise a new, more lucrative offtake contract to replace the one initially awarded to the partners. 

In the latest development, GIP will buy Eversource’s share of South Fork and Revolution. Eversource expects to realize approximately $1.1 billion in cash proceeds from the deal but said that could be higher or lower because of factors including construction costs, tax credit eligibility and project delays. 

An 8-K filing by Eversource on Feb. 13 indicates that GIP is guaranteed a pretax equity internal rate of return of 13% for Revolution and South Fork upon the start of commercial operations; if it is less, Eversource will pay GIP the difference, and if it is more, GIP will pay Eversource. 

The transaction cannot close without federal and state approvals. 

In a call with financial analysts the morning of Feb. 14, Eversource CEO Joe Nolan immediately launched into discussion of the proposed sale. 

“When we started down this path in 2016, we were very excited for the opportunity to bring much needed renewable energy to our region,” he said. “Unfortunately, our offshore wind investment experienced difficulties as early-stage projects.” 

These problems — inflation, interest rates, shortage of material and dearth of specialized vessels — came to the fore in late 2022, after several projects off the Northeast coast already had locked in offtake contracts at fixed rates, thus rendering the projects financially untenable. 

Developers in Massachusetts, Connecticut, New York, New Jersey and Maryland canceled projects or put them on hiatus; canceled offtake contracts; and dissolved partnerships. Ørsted took over Public Service Enterprise Group’s share of a now defunct New Jersey project, while Equinor and BP have agreed to divvy up their proposed wind farms off New York and New England. 

If all the pieces come together for Eversource, it will be a chance to exit offshore wind and refocus on gas and electricity with its feet firmly on land. 

“Our core business is well positioned to deliver solid operational and financial results as we move forward in supporting the region’s transition to a cleaner energy environment,” Nolan said. “Moving forward, Eversource will focus on the delivery of clean, safe, reliable energy to our customers.” 

In another 8-K filing Wednesday, Eversource reported a net loss of $442 million for 2023, which compares with net income of $1.4 billion in 2022. That breaks down to a 2023 loss of $1.26/share and 2022 earnings of $4.05/share. 

As Nolan indicated, the onshore businesses performed well: Electric, gas and water distribution, and electric transmission generated earnings of $4.34/share, compared with $4.09 in 2022. 

But impairments totaled a loss of $5.60/share for 2023, all but 2 cents of it attributable to offshore wind. 

The pretax impairment for 2023 was $2.17 billion: $400 million for Sunrise and South Fork in the second quarter, $545 million for Revolution in the fourth quarter and $1.22 billion for Sunrise in the fourth quarter. 

A $215 million tax benefit brought the after-tax impairment down to $1.95 billion for 2023.