NYISO on Jan. 30 requested a three-year extension to comply with FERC Order 881, claiming it needs more time to implement the software and hardware updates necessary to support the required ambient-adjusted ratings (AARs) on its transmission lines (ER22-2350).
Order 881 mandates that providers assess transmission capacity based on real-time environmental conditions, such as temperature or wind, requiring the use of AARs for short-term transmission requests and seasonal ratings for long-term requests (RM20-16). NYISO says it needs more time to comply with the order because it also must undertake a multiyear effort to upgrade its Energy Management and Business Management Systems (EMS/BMS), which are critical to monitoring reliability and managing financial operations.
NYISO was slated to implement Order 881’s enhancements by the second quarter of 2025 but now is asking for an extension of no later than Dec. 31, 2028, arguing it is infeasible to both comply with the commission’s order and deploy the nine EMS/BMS software modifications necessary to support the order’s requirements. (See “Ambient-adjusted Ratings,” NYISO Management Committee Briefs: Nov. 29, 2023.)
The ISO had been upgrading its EMS/BMS software but now contends meeting the current deadline requires a substantial reallocation of resources and personnel, which, it states, “would jeopardize the timeline and quality assurance efforts required to successfully complete a critically important technology upgrade.” It added that it cannot use these operating systems past their June 2026 vendor support date “without risking significant software failures.”
Moreover, NYISO pointed out transmission owners (TOs) cannot fulfill their own Order 881 obligations until the ISO has the requisite software and protocols in place. But it assured FERC that if granted an extension, it would maintain certain dynamic line rating functions to still give TOs the ability to modify real-time transmission line ratings.
In an attached affidavit, Rana Mukerji, senior vice president of market structures at NYISO, wrote that a compliance extension was needed because certain modifications “were not anticipated in the initial scope for this technology upgrade project and the initial project schedule.”
He cautioned that, in his experience, without an extension, “coding two sets of major modifications in parallel within the same systems significantly increases the possibility that one or both software changes result in increased implementation times and errors.”
Mukerji added, however, that if given an extension, it still would take two-and-a-half to three years to complete and implement the EMS/BMS upgrades.
NYISO asks FERC to respond by March 29, because the ISO plans to begin its 2025 project prioritization process in April and wants to know if it can proceed with the EMS/BMS project in the coming year.
FERC on Jan. 30 released the latest iteration of its Common Metrics Report on ISO/RTO markets, which evaluates the performance and benefits of organized markets.
The commission has released these reports every few years since Congress’ Government Accountability Office suggested it do more to track the performance and benefits of ISO/RTOs back in 2008. The report shows the different fuel mixes from FERC’s six jurisdictional organized markets and how much they each rely on demand response.
Some past reports have included similar data from utilities outside of ISO/RTO footprints, but none of them responded to FERC’s efforts this time.
The highest share of DR is in CAISO at 10%, while MISO, NYISO and PJM each have 3-6%. ISO-NE and SPP both reported less than 2%. DR in SPP grew significantly in 2022, hitting about 2% after minimal levels in earlier years.
ISO-NE and MISO added generation in each year from 2019 to 2022, while both PJM and NYISO lost capacity overall during that time.
FERC staff collected information on 29 common metrics across the six ISO/RTOs split across three broader categories: administrative and descriptive metrics; energy market metrics; and capacity market metrics.
CAISO, ISO-NE, MISO and NYISO all had actual reserve margins below their expected levels between 2019 and 2022, with MISO seeing the biggest gap. Only PJM had higher actual reserve margins than expected in all four years, while SPP flipped between both categories every year.
Every organized market reported that natural gas was their single largest fuel type from 2019 to 2022 with NYISO seeing the biggest increase in the fuel — from 58% to 64% — while ISO-NE, MISO and PJM each reported a modest increase. CAISO saw natural gas share fall from 49% to 41% over the period, while SPP saw a more modest drop from 43% to 40%.
“The decline in the share of natural gas-fired capacity in these regions is likely driven by the relatively large increases in wind and solar generating capacity, instead of natural gas retirements,” the report said.
MISO, PJM and SPP all had a significant amount of coal in the fuel mixes, and all saw it drop. Coal in PJM fell from 30% in 2019 to 25% in 2022, MISO saw it fall from 41% to 37% and SPP from 25% to 22%. The other markets all reported less than 3% coal in their markets.
SPP and CAISO had the highest shares of installed wind and solar generating capacity, with the two renewables representing 31% of capacity in SPP and 30% in the California ISO.
“The largest relative increase in generating capacity of these resource types occurred in SPP, where the share of wind and solar capacity increased from 24% in 2019 to 31% in 2022,” FERC said.
The report also included how often each market had to issue Energy Emergency Alerts across the four years studied, with CAISO seeing 16, MISO 10, PJM six, SPP five and ISO-NE one.
FERC issued an order Jan. 31 approving the return of $13.6 million in penalties it had collected from BP over a case of alleged manipulation of Houston Ship Channel natural gas prices after Hurricane Ike in 2008.
The commission collected $24.36 million in fines, plus interest, from BP for allegedly keeping natural gas prices at the Houston Ship Channel lower than those at the Henry Hub in Louisiana and losing money in physical trades, which benefited its financial positions and led to overall profits. FERC first issued a show cause order in the case in 2013, and years of litigation followed until a decision from the Fifth Circuit Court of Appeals came down in October 2022.
The commission had argued it should have jurisdiction over any transaction that impacts the interstate natural gas markets it polices, but the court disagreed.
BP only shipped gas over intrastate pipelines regulated by the Texas Railroad Commission in the alleged scheme, but some of that natural gas previously had crossed state lines, meaning it fell under FERC’s jurisdiction. The court said only that interstate gas could be part of the federal regulator’s enforcement action.
BP and FERC’s Office of Enforcement entered into a settlement that trimmed the penalty to $10.75 million, following the court’s findings, which meant the firm had paid an extra $13.6 million.
The oil major agreed it would not seek recovery of $250,295 of disgorgement of unjust profits, which ultimately was paid to three Texas Low Income Home Energy Assistance Program (LIHEAP) programs.
BP made a filing in November arguing FERC itself should issue an order requiring it be repaid for the $13.6 million. The order Jan. 31 directed the director of the Financial Management Division in the Office of Executive Director to wire BP the money.
Backers of the recently formed Western Transmission Expansion Coalition want to fill a void in the Western Interconnection by producing an “actionable” interregional transmission study — one that starts with a holistic view of the region’s needs.
“The idea here is that we’re looking at that entire collective footprint, and not just the subregions,” Sarah Edmonds, CEO of the Western Power Pool (WPP), said during a Jan. 29 call to update stakeholders on the WestTEC effort, which was launched last October. (See Plan Seeks to Boost Prospects for New Transmission in the West.)
Edmonds explained the meaning of “actionable.”
“We want to provide high-confidence information to the industry so that if there are parties who are interested in advancing transmission build solutions, they can take the information out of our study, knowing that the study has a high-confidence factor built by all of the different participants,” including states and tribes, she said.
“We don’t deny that cost allocation, permitting and siting are complicated matters and that, in many ways, this study is the easiest part of a journey towards transmission solutions,” she said. “So when we say ‘high confidence,’ we’re really hoping that the study itself will really grease the skids for future conversations around all of those things.”
Former FERC Chair Richard Glick, now a principal at GQ New Energy Strategies and a consultant for WestTEC, spoke on the call, emphasizing the need to stay focused on the planning end of transmission development.
He pointed to the region’s growing concerns around resource adequacy, rising demand from electrification and increasing instances — and “ferocity” — of extreme weather events. Glick noted also that the Department of Energy’s most recent National Transmission Needs Study noted that the Northwest and Southwest could require an additional 30% of transmission capacity by 2035.
“As I think most people have seen, there’s been some frustration that the current approach to regional transmission planning in the West — particularly outside of the California ISO — has not been very effective,” he said.
Issues of cost allocation and siting are being picked up elsewhere, Glick said. Western state officials have started moving to address regional transmission cost allocation, as evidenced by the state-led Western States Transmission Initiative.
And given the scale of federal ownership of land in the West, siting and permitting are being addressed at the federal level.
“I know the Department of Energy now is taking the lead in terms of being the lead siting agency at the federal government,” Glick said. “There’s a number of bills pending in Congress right now that would attempt to facilitate and improve the transmission siting environment that currently exists.”
‘Biggest Tent Possible’
Inclusivity was a key theme during the call.
“WestTEC is about expanded engagement,” Edmonds said, noting the organization has sought to become West-wide and move beyond the participation of just transmission-owning utilities.
Ben Fitch-Fleischmann, director of markets and transmission at the Interwest Energy Alliance, lauded WestTEC for providing a seat at the table for trade associations such as his. He noted the group’s roster already includes utilities, independent power producers, the region’s three transmission planning entities, National Laboratories, state agencies, tribal representatives and the Western Interstate Energy Board.
“So aiming to pitch the biggest tent as possible,” Fitch-Fleischmann said.
WestTEC will seek to prioritize inclusivity through its proposed governance and committee structure, which would include the Steering Committee, Regional Engagement Committee (REC) and WestTEC Assessment Technical Team (WATT).
The Steering Committee, which will oversee the effort, will be “substantially West-wide in its representation,” Edmonds said. The committee will include representatives from transmission-owning utilities from across the West, the region’s three planning groups — CAISO, NorthernGrid and WestConnect — and WECC.
The REC would seek “a broad membership to make sure we’re aligned with state policy and consumer interests,” according to Fitch-Fleischmann. Its job will be to review the work of the WATT, gain insights from the region and provide feedback.
“We need to ensure we get timely input from a wide range of governmental agencies, public interest perspectives and the like to make sure we can engage with the broader public,” he said.
The WATT will be charged with getting into the weeds around the study.
“This is not a committee where we’re looking for another warm body,” said Chelsea Loomis, WPP manager of regional transmission planning services. “We need people who can really hit the road and contribute with data that will support the study scope. We need to make sure that we are developing the scenarios that support the execution of that study scope. This will be a very busy group.”
Members of the WATT also recently selected consultants to assist in modeling for the study: Energy Strategies, with support from Energy+Environmental Economics.
WestTEC is seeking funding to support its work, just like another big effort taking shape in the Western electricity sector: the West-Wide Governance Pathways Initiative. Edmonds said WestTEC recently completed an application for a DOE grant that seems “tailor made” for its work.
“But I really want to emphasize that it is not a condition for us moving forward,” she said. “We’re going to find a way to fund this amongst ourselves, and if DOE funding comes along, that will be very helpful. But we’re not waiting around for that determination.”
House Republicans on Jan. 30 lambasted a deal that the Biden administration struck between Oregon, Washington and four tribes on four dams along the Snake River, claiming it will lead to their breaching and threaten power reliability and other industries.
The administration announced the deal in December, and Democrats on the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security argued it would end uncertainty around the four Bonneville Power Administration (BPA) dams, which had been under litigation for decades because of their impact on salmon and other fisheries.
The Columbia River System is the “beating heart” of the Northwest, and removing the four dams would imperil electric reliability in that region and the broader West, committee Chair Cathy McMorris Rodgers (R-Wash.) said.
“While the administration will say only Congress has the authority to breach the dams, they wasted no time entering into commitments that bypass Congress and agreeing to spend more than a billion dollars to achieve their political goal, again without congressional approval,” she added. “What’s worse is, despite my repeated calls for transparency, the White House actively and deliberately left out voices of those who depend on the river system the most. Dozens of stakeholders and utility companies practically begged to be heard in this process, only to be turned away, shut out and ignored.”
The Columbia River is home to 13 species of salmon that are endangered, and the tribes who live along it have depended on their annual runs for thousands of years, said subcommittee Ranking Member Diana DeGette (D-Colo.).
“Construction and operation of the dams, private dam building and population growth have negatively impacted wild fish populations,” DeGette said. “This has led to years of litigation and court rulings, which have found operation of the dams violates the Endangered Species Act.”
Treaty obligations to the tribes allow them to harvest 50% of the salmon catch; the fish’s declining numbers violated those obligations, said Yakama Nation Tribal Council Member Jeremy Takala. “My people’s tribal treaty rights demand it, as the U.S. Supreme Court recently affirmed treaty fishing rights include the right to actually catch fish, not just to dip our nets in empty waters without salmon.”
Takala was involved in the negotiations on behalf of his tribe that led to the deal, which came out of a recent court case.
“In 2021, a group of plaintiffs filed a motion for the most recent district court litigation seeking to further alter hydropower operations in the basin,” said White House Council on Environmental Quality Chair Brenda Mallory. “The United States government had a choice: defend and face the prospect of another injunction, or work with the plaintiffs and others in the region to find a path forward that could lay the groundwork for an enduring partnership with mutually beneficial solutions. We chose partnership.”
The CEQ convened an interagency group and engaged mediators to facilitate a dialogue with tribes and states in the region, which last fall led to a Presidential Memorandum of Understanding on preserving fish stocks in the region. In December, the White House announced the deal with the “six sovereigns” (the two states and four tribes), which includes more fishery restoration efforts, funding for clean energy development by the tribe and a pause of at least five years in the ongoing litigation, with the possibility of another five.
BPA has been working for decades to improve the environment for salmon and other fish. The deal includes additional funding to improve fisheries over the coming decade, said CEO John Hairston. BPA filed a rate impact statement showing that those additional funds would only add an average of 0.7% to customers’ monthly bills through 2035.
National Rural Electric Cooperative Association CEO Jim Matheson disputed the relatively low cost estimates coming out of BPA.
“If you want to build replacement power when you breach these dams — which I don’t think you can do and have the same comparable resource, by the way — you’re going to spend a lot of money, and it will have a big impact,” Matheson said.
The four dams are also highly complementary to the region’s wind resources because they all have technology that allows them to ramp up and down quickly depending on how hard the wind is blowing, Matheson said.
The agreement filed in court recognizes that Congress must enact legislation to actually breach the dams, but Matheson argued the deal was piling more and more compliance costs on them.
“This settlement effort is a way to force Congress’ hand and put Congress in a position where breaching is more likely,” he said.
Matheson declined to use the word “secret” that was often repeated by Republicans at the hearing about the negotiations, but he did note that just six parties were in the room with the federal government, and so far NRECA and other industry representatives’ letters taking issue with it have not been answered.
The Yakama Nation’s Takala opened his testimony by calling claims about secret negotiations with “radical environmental groups” as claims “fueled by fear and misinformation.”
“This agreement is a historic opportunity to help save our salmon and secure a just and prosperous future for everyone in the Columbia Basin,” Takala said. “First, for clarity, the Yakama Nation is not a radical environmental special interest group.”
Its rights to salmon from the rivers are guaranteed by the treaty the tribe signed with the federal government in 1855, he added.
“Since time immemorial, the strength of our Yakama Nation and its people have come from the Nch’í-Wána — ‘the big river,’ or the Columbia River — and its tributaries and from the fish, game, roots and berries nourished by their waters,” Takala said.
FERC has approved a new reliability standard intended to prevent conflict between registered entities’ protective relay settings and grid operators’ ability to protect reliability, nearly a year after NERC’s Board of Trustees approved the standard.
NERC’s board adopted the standard, which was developed as part of Project 2021-05 (Modifications to PRC-023), at its meeting in Tucson, Ariz., last February. (See “New Standards Sent to FERC,” NERC Board of Trustees/MRC Briefs: Feb. 15-16, 2023.) The commission gave its assent to PRC-023-6 (Transmission relay loadability) Jan. 25 in a delegated letter order (RD23-5).
As explained in NERC’s petition for approval, the new standard is intended to retire “redundant and unnecessary language that has contributed to confusion regarding” the applicability of previous versions of the standard to power swing blocking (PSB) relays. PSB, also called out-of-step blocking, is installed in long-distance transmission relays to prevent tripping during stable power swings.
Project 2021-05 was initiated after stakeholders expressed concerns that the standard “could lead to increased reliability risk by entities limiting or disabling their [PSB] elements.” The specific issue, according to NERC, was requirement R2, which mandated that transmission owners, generator owners and distribution providers set their PSB elements “to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability.”
NERC told FERC in its petition that the team for Project 2021-05 determined that this requirement is redundant because R1 addresses the same “fault condition” as R2 and “requires the same entity response.” R1 provides a set of criteria for entities to use to “prevent [their] phase protective relay settings from limiting transmission system loadability … for all fault conditions.”
The team observed that noting a specific fault condition, as R2 does, is unnecessary because R1 already covers all conditions. In addition, R2 “does not support directly the purpose of the … standard,” which mandates that protective relay settings not interfere with “operators’ ability to … protect system reliability and [shall] be set to reliably detect all fault conditions and protect the electrical network from these faults.”
NERC’s petition also noted that PRC-027-1 (Coordination of protection systems for performance during faults) “addresses the same reliability concern as … R2 in a much clearer and more comprehensive fashion.” That standard requires entities to coordinate their protection systems to ensure they operate in the intended sequence when faults occur.
The ERO said that in the event that a PSB relay did not allow tripping, “an unintended sequence of tripping” could result in other relays tripping through backup protection systems.” This would mean the coordination was not designed properly, a violation of PRC-027-1. NERC considered this further evidence that the older standard’s requirement was unnecessary, because an entity could still be audited for the PSB failing to trip.
In approving the standard, FERC noted it received no comments, protests or motions to intervene when the ERO’s petition was published in the Federal Register. The new standard will take effect on April 1, 2024, the intended effective date of PRC-023-5. The latter standard was approved in May 2021 to replace the currently effective standard PRC-023-4, but NERC asked FERC in its petition to let the new standard supersede it.
FERC on Jan. 29 approved ISO-NE’s proposal to create a day-ahead ancillary services market and retire the current Forward Reserve Market (FRM), effective March 1, 2025 (ER24-275).
Dubbed the Day-Ahead Ancillary Services Initiative (DASI), ISO-NE and NEPOOL jointly filed the proposal at the end of October. The new market will procure operating reserves and fill any gaps between the amount of energy procured in the Day-Ahead Energy Market (DAEM) and the load forecast.
“We are pleased with the approval by FERC to create a day-ahead ancillary services market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized day-ahead market,” ISO-NE told RTO Insider in a statement.
With climate change increasing weather variability as the resource mix shifts toward weather-dependent resources, DASI will “encourage reliable resource performance and prepare the system on a day-ahead time frame with the flexibility needed to manage these new operational uncertainties,” ISO-NE said.
ISO-NE and NEPOOL noted in their joint filing that the existing DAEM “only procures energy to meet bid-in demand, and if the load forecast exceeds the amount of cleared energy from physical suppliers, there remains what the ISO refers to as a day-ahead ‘energy gap.’”
The RTO currently relies on out-of-market solutions to identify resources to fill these energy gaps and provide operating reserves.
“This process results in both under-compensation to those resources identified to provide these capabilities during the operating day and no specific financial obligation or incentive for such resources to be prepared to perform in real time in accordance with the operating plan,” the proposal said.
The ancillary services market will be run in conjunction with the existing DAEM; it will procure 10-minute spinning and non-spinning reserves and 30-minute operating reserves. It will also include an “Energy Imbalance Reserve” product, which is intended to fill energy gaps between the DAEM and the load forecast.
“DASI will provide targeted compensation and clear financial obligations and incentives for the flexible resources on which the region currently relies, and on which it will increasingly rely as the region heads into the future,” the filing said.
DASI will replace ISO-NE’s FRM, which provides forward seasonal payments for resources to provide 10-minute non-spinning reserves and 30-minute operating reserves. ISO-NE has said the FRM is incompatible with the implementation of DASI.
ISO-NE noted that an analysis of projected DASI revenues based on a 2019-2021 study period found that the initiative would increase annual wholesale market costs by about $104 million, or about 1.1%. The study indicated that the ancillary market would generate “substantial revenues” for storage resources, ISO-NE added.
The joint filing was supported in comments by the New England States Committee on Electricity, the Electric Power Supply Association, the National Hydropower Association and the New England Power Generators Association.
Meanwhile, LS Power expressed concern that replacing the FRM with DASI could decrease revenue for flexible resources.
“The overall DASI proposal will cut revenues for flexible generation by as much as 94%,” the company wrote in its comments, adding that DASI could introduce “unreasonable and undercompensated risks” for peaking resources.
In response, ISO-NE disputed LS Power’s revenue calculations. The RTO noted that its impact assessment found that total net revenues for ancillary service suppliers would decrease by only about $5 million annually, adding that this assessment “may understate the revenues that will be earned by reserve-capable suppliers, compared to those currently earned through the FRM.”
The DASI filing requires ISO-NE’s Internal Market Monitor “to issue ad hoc reports on the competitiveness of any major market design change within one year of the effective date of operation, and on its performance within three years.”
The RTO recognized requests from stakeholders for longer-term reserves and wrote that it plans to kick off discussions on longer-term products for the real-time and day-ahead markets in 2025.
FERC found that DASI will “materially improve operating reserve resource readiness, efficiency and day-ahead price formation in ISO-NE without undue increases in wholesale market costs.”
The commission expressed skepticism of the concerns raised by LS Power, writing that the company “does not demonstrate that revenue levels under DASI, which result from market-determined clearing prices, will not be just and reasonable for the purpose of procuring and compensating operating reserves.”
In a concurring statement, Commissioner Allison Clements expressed strong support for the changes.
“The DASI reforms appear to be an important step forward for ISO New England’s ancillary services market and one reflecting the region’s evolving operational needs as its resource mix changes,” Clements wrote.
“For a proposal of this complexity to have near universal support in the record and unanimity in the stakeholder process is a testament to the hard work and productive collaboration of many in New England,” she added. “It is worth taking a moment to give credit where credit is due.”
New Jersey’s mass transit agency has abandoned a more-than-$500 million plan to build a gas-fueled emergency resiliency generator amid sustained opposition from environmental groups.
NJ TRANSIT, which runs 12 commuter rail lines linking the state with New York and Philadelphia, said the plan — known as TransitGrid Central Facility — was “not financially feasible.” The agency said it would take the $503 million in federal grants designated for the plant and use the money for other projects, including a new bridge, upgrading of a rail yard and expanding a rail terminal.
The transit agency walkback comes after a year in which the New Jersey Department of Environmental Protection (DEP) in April put in place the final rules for a tough new environmental justice law and held a series of “public engagement” sessions around the state to solicit residents’ concerns about environmental issues.
NJ TRANSIT proposed the 140-MW gas generator and microgrid in Kearny, N.J., after Superstorm Sandy in October 2012 caused widespread and prolonged power outages that severely affected rail service for nearly a week. Despite the agency’s statements the generator would be used for only resilience, opponents for years have argued the state shouldn’t be creating new gas plants as it strives to cut carbon emissions and rely on renewable energy.
“While the TransitGrid procurement process provided valuable knowledge for the future, it showed the funding would be better used to protect these other critical points around the state,” NJ TRANSIT CEO Kevin S. Corbett said in a release Jan. 26 that announced the shift in funding away from the project.
The release said “all of the these affected projects within the Sandy Resilience program are critical pieces of rail infrastructure, including bridges, safe haven storage yards and infrastructure located directly on waterfront properties bearing the brunt of past and future storm events.”
The release added that because the agency proposed the project, “multiple improvements to the affected power grid have been enacted that have functionally made the MCF as envisioned at that time much less necessary than other critical resiliency projects.” In particular, PSE&G has made “significant investments in power grid resiliency under a program called “Energy Strong” throughout the region that has greatly increased power reliability,” the release said.
Anjuli Ramos-Busot, director of the New Jersey Sierra Club, welcomed the agency’s reversal on the “harmful project,” saying her organization had said for years that it’s not financially viable.
“This decision recognizes that gas is not the future for New Jersey and [we] hope that we can continue to move in the right direction toward renewable energy alternatives, battery storage and incorporating climate resilience into everything that we do,” she said. “This decision is a win for the local communities who are overburdened with air pollution, particularly Kearny.”
Providing Storm Resiliency
The Department of Environmental Protection outreach effort comes amid a realization among government officials, planners and developers in New Jersey and elsewhere that community outreach and securing local buy in are key to implementing energy projects and ensuring they advance smoothly.
New Jersey until late last year had six planned gas generating plants, and the Kearny plant was one of three such facilities in North Jersey that for years have drawn particularly vigorous opposition because of their proposed locations in overburdened communities. Only one of the three North Jersey plants now remains on the drawing board.
On Oct. 11, developer Competitive Power Ventures (CPV) withdrew its plans for a 630-MW gas-fired generating plant under development in the Keasbey section of Woodbridge, which local residents opposed. CPV said after it abandoned the gas-fired plant, which would have been the company’s second in that township, that the plant was no longer feasible because market conditions had changed. (See Electric vs. Gas Skirmish Rising in NJ.)
Superstorm Sandy stimulated the development of the third controversial gas plant by the Passaic Valley Sewerage Commission (PVSC), which describes itself as the fifth-largest publicly owned wastewater treatment facility in the U.S. The facility lost power for three days after the 2012 storm, resulting in 840 million gallons of raw sewage pouring into the Passaic River and New York Harbor.
Newark-based PVSC wants to build a $600 million “integrated natural disaster resiliency project” that would serve as a standby power generation facility. The plant would include three 24-MW combustion turbine generators and two 2-MW natural gas-fueled generators.
Early on, PVSC also planned for the plant to provide “peak load management” service to PSE&G’s grid when it came under heavy load demand. But the agency withdrew that plan in June 2021 in the face of public opposition. Activists have urged the PVSC to consider powering the resiliency project with renewable energy. But the agency has said gas would be a better option, although the project website says that “doesn’t mean that renewable energy and alternative fuel sources aren’t an option down the road.”
Public Concern
Opposition to the three projects has surfaced frequently at the DEP’s public engagement meetings, and the issue was highlighted by a speaker at an Oct. 17 meeting in Hudson County, which includes Kearny, the site of NJ TRANSIT’s now-abandoned project. The series of meetings is supported by the federal EPA’s Region 2 office.
Elizabeth Ndoye, a Hoboken, N.J., resident and a member of Don’t Gas The Meadowlands, a group that opposes the development of fossil fuel generators, gave the DEP’s October meeting a succinct snapshot of how she feels climate change has impacted her life.
“I am a 75-year-old mother who will never be a grandmother,” Ndoye told the meeting in Union City, N.J. “Because my daughter-in-law refuses to have grandchildren because we are living in a time of climate crisis. So I am being robbed of the natural joy of most women on this planet.”
As a dedicated environmentalist, she said, she takes pride in CPV’s abandonment of plans to create a gas-fueled plant in Central New Jersey.
“We stopped it in Woodbridge,” she said, and concluded her comments by saying New Jersey Gov. Phil Murphy (D) must “stop these horrible carbon-based dirty fossil-fuel projects.”
Confronting Historic Injustice
In New Jersey, concern that communities were not being heard in decisions over environmental issues led to the enactment of the state’s environmental justice law, which took effect in April with the adoption of the final rules. On signing the law in September 2020, Murphy called it a “historic step” that made the state “home to the strongest environmental justice law in the nation.”
The law requires the DEP to evaluate environmental and public health impacts of certain facilities on overburdened communities (OBCs) when they seek permits. The DEP says it makes New Jersey the first state able to “issue denials for new facilities that cannot avoid disproportionate impacts on OBCs or serve compelling public interest.”
At the heart of the law, according to the DEP, is the legislature’s belief that “historically, New Jersey’s low-income communities and communities of color have been subject to a disproportionately high number of environmental and public health stressors” stemming from the “numerous industrial, commercial and governmental facilities” placed in those communities.
The new environmental justice law means that while the DEP in the past looked at the pollution impact of potential facilities over wide geographic areas, the state also now must look at the local impact and how it affects “a community’s fundamental right to live, work, learn and recreate in a clean and healthy environment,” the DEP says.
Applicants seeking environmental permits for certain pollution-generating facilities must follow new procedures that include identifying environmental and public health stressors from the proposed facility. Applicants also must ensure that meaningful public participation by members of the host community takes place.
The law also empowers the DEP to take into account those stressors and study the concentration of facilities in a given area.
High Density Environmental Impact
Kandyce Perry, director of the office of environmental justice, opened the Union City meeting by saying that though the meeting was part of an ongoing public input solicitation process, the area around the meeting was distinct.
“Here in Hudson County, the densest county in the state, which is already the densest state in the country, communities are contending with compacted neighborhoods that abut against industry, traffic congestion and historic brownfield sites,” she said.
“As our climate gets warmer, the most vulnerable of our residents within Hudson County will be hit hard,” she said. “And this is why it is so important for government to hear directly from those of you who are most impacted by these experiences.”
Key deadlines already have arrived for MISO’s spring capacity auction, while the RTO has hiked its planning reserve margin for the 2024/25 planning year.
So far for the upcoming summer, MISO has accounted for nearly 161 GW in installed capacity across the footprint that whittles down to almost 129 GW in total seasonal accredited capacity. The RTO must meet a 135.7-GW summer planning reserve margin requirement.
MISO will use a 9% summer 2024 planning reserve margin, higher than the 7.4% annual planning reserve margin used in last year’s Planning Resource Auction. MISO said its shifting resource mix and a move to seasonal modeling for its reserve margin contributed to the increase. This year, the RTO said it’s using seasonal values, rather than annual, in its generator verification testing data, reflecting different capabilities of generators in different temperatures. The upcoming spring auction marks the second time MISO has divided its capacity auction by season.
MISO stressed Jan. 17 that it’s “too early in the process to make quantifiable conclusions” on how much supply it expects beginning June 1.
The grid operator plans to update its supply information based on the data it receives from market participants every other week through late March. It said it expects information on energy supply to change “significantly.”
MISO resource owners have until Feb. 1 to confirm their seasonal accredited capacity values with the RTO. Load-modifying resource owners also have until Feb. 1 to register to participate in the auction. As of mid-January, MISO said approximately 12.8 GW of load-modifying resources from prior years had not started the registration process.
MISO confirmed Jan. 30 it likely will try again with FERC in the third quarter to apply an annual megawatt cap to its interconnection queue.
FERC in December denied MISO’s request to annually cap submittals to its interconnection queue on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.)
MISO said it will apply the rules FERC did approve to the 2023 cycle of project requests, which has been on pause since last year for FERC’s decision on the package of more stringent interconnection requirements. The new rules include increased entry fees, an automatic penalty schedule for withdrawing projects and added proof that developers have secured locations for projects.
MISO said it will belatedly open its 2023 queue cycle project window on March 18 and close it on April 18. That cluster of projects will not be subject to a megawatt cap. Currently, the RTO’s online generator interconnection portal remains closed to new applications.
MISO hasn’t abandoned the idea of a megawatt cap on future queue cycles. The grid operator plans to again propose a megawatt cap that first could apply to the 2024 class of projects.
Aneta Godbole of MISO’s resource utilization team said FERC “provided good guidance that MISO will use in its future refiling efforts.”
“MISO will come back to the stakeholders once it is ready for further discussion,” Godbole said of a second cap filing during a Jan. 30 teleconference of the Interconnection Process Working Group.
At this point, the RTO intends to begin processing both a 2023 and 2024 cycle of generation project requests this year. It said if all goes to plan, it could place the 2024 queue cycle deadline at the end of the year.
“MISO is anticipating two cycles in 2024, but it depends on our work to reduce the backlog, the size of the 2023 cycle, the cap filing and approval of the” long-range transmission plan (LRTP) and the MISO-SPP Joint Targeted Interconnection Queue (JTIQ) transmission portfolios, Godbole said. MISO previously said the regional LRTP and the interregional JTIQ will help support new generation interconnections.
Additionally, MISO said either its 2024 or 2025 class of project requests will be the first to proceed under FERC’s Order 2023 queue requirements, depending on the final effective date.
Some stakeholders were incredulous that MISO could handle the workload of two queue cycles in a single year given the uptick in project submittals.
“There are a lot of factors on when we hold the next queue cycle,” MISO’s Andy Witmeier added. He said the RTO wants to be transparent about which factors it foresees dictating when it can open a 2024 queue cycle.
At the Jan. 24 Planning Advisory Committee, Witmeier called a megawatt cap a “vital tool.” He also said MISO won’t file to apply a megawatt cap retroactively to projects in the queue.
