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November 5, 2024

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NY State Agencies Support NYPA Smart Path Project

New York’s departments of Agriculture and Markets (AGM), Public Service (DPS), and Environmental Conservation (DEC) this month approved a joint proposal by them, the New York Power Authority (NYPA) and National Grid (NYSE:NGG) for completion of phase 2 of the 100-mile Smart Path transmission line rebuild project (21-T-0340).

The Smart Path project is part of NYPA’s $1 billion Northern New York transmission line, which the Public Service Commission in October 2020 designated as a high priority for meeting the state’s renewable energy goals, bypassing NYISO’s public policy transmission planning process (20-E-0197). (See NYPSC OKs NYPA Project, ‘Priority’ Tx Criteria.)

The AGM said that its concerns and issues were addressed in the proposal and its appendices.

“Environmental impacts have been minimized by siting the proposed transmission line within existing rights of way to the greatest extent practicable,” it said. “Because the project predominantly uses existing ROW, there will be virtually no discernable change in land-use conditions along the transmission line portion of the project. Additionally, the project represents the minimum adverse impact on active farming operations, considering the state of available technology and the nature and economics of alternatives and other pertinent considerations.”

The DEC said that “there are no further issues for litigation concerning the application.”

John B. Donahue, a resident of Lyons Falls, about 30 miles north of the city of Rome, had commented June 8 that he and his wife, Bonnie, “are all for the upgrade to the power lines, but then they said they wanted another 12.5 feet of our property; we were taken by surprise because it sounded like it was a done deal and we had nothing to say about it. I know this project is huge and entails hundreds of miles of ROW and 12.5 feet is not very much, but this would severely impact our lives here.”

In its letter of approval a week later, the DPS commented that Donahue’s concerns will be addressed through project design changes made during development of the environmental management and construction plan that no longer require expansion of the ROW onto his property.

“The only remaining property acquisition at this location would be National Grid’s acquisition of danger tree rights in order to comply with the proposed certificate conditions should they be adopted by the commission,” DPS staff said.

A danger tree is defined by the commission as “any tree rooted outside of a ROW that due to its proximity and physical condition … poses a particular danger to a conductor or other key component of a transmission facility.”

By definition, a danger tree must exist outside of the ROW. Therefore, any necessary acquisition of danger tree rights would not constitute an expansion of the ROW and would only give National Grid the right to remove any trees that pose a risk to the transmission line, the DPS said.

Attorney Thomas S. West, representing the town of Burke, submitted a letter June 16 stating that the town is not able to support the proposal, as there are still outstanding issues under negotiation concerning the resolution of issues associated with potential impacts to local roads.

“We are in negotiations with NYPA and hope to conclude those negotiations in the near term. In the absence of finalizing those negotiations in a manner acceptable to the town, we reserve all rights to request a hearing concerning road impact issues,” West said.

National Grid proposes leasing 7 acres of paved, but unused, runway at the Griffiss International Airport in Rome as one of two staging areas for Smart Path project construction.

Marcy resident Thomas N. Rastani Jr. commented June 24 that the project’s design more than doubles the height of the transmission towers, to 135 feet, which would make them “clearly visible from the road approaching my home, or anywhere on my property.”

In addition, increasing the voltage capacity from 230 kV to 345 kV for two lines will increase the noise levels substantially, along with an increase in electromagnetic waves, he said.

“Overall, this proposed line will disrupt the wildlife (which is why I purchased this property to begin with); it will disrupt the quality of life during construction; and it will leave a lasting impact with the increased electromagnetic waves and increased noise pollution that myself and my neighbors will be forced to endure,” Rastani said.

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California PUC Approves New Resource Adequacy Construct

The California Public Utilities Commission on Thursday approved changes to the state’s resource adequacy requirements meant to bolster its ability to withstand extreme weather events like those that led to energy emergencies in recent summers and to account for the replacement of thermal generation with wind, solar and battery storage.

“The goal is a framework that can ensure resource sufficiency for grid reliability in all hours of the day, even as the state’s energy mix evolves and statewide load increases,” CPUC President Alice Reynolds said, referring to the state’s move toward 100% carbon-free resources by 2045 and its efforts to electrify buildings and transportation.

In its decision, the CPUC adopted a proposal by Southern California Edison for a “24-hour slice” that requires each load-serving entity to show it has enough capacity to satisfy its specific gross load profile, including a substantial planning reserve margin, in all 24 hours on CAISO’s “worst day” of each month.

“The worst day would be defined as the day of the month that contains the hour with the highest coincident peak load forecast,” the decision said. “For an LSE that uses energy storage to meet requirements, the LSE must demonstrate it has excess capacity that offsets the storage usage plus efficiency losses. An LSE could combine the capabilities of its resource mix to cover all 24 hours.”

The CPUC decided to revise its 16-year-old RA framework in response to “recent trends and concerns that have arisen, which have led to the commission’s re-examination of the RA program to ensure that the framework can provide grid reliability at all times of the day,” the decision said.

In particular, the commission had relied on a maximum cumulative capacity (MCC) “bucket” structure that it said was no longer adequate.

“The MCC bucket requirements are developed using average monthly summer load duration curves and monthly resource use limitations to prescribe cumulative caps that limit how much LSEs can rely on certain resources in meeting monthly RA requirements,” the decision said.

The MCC buckets largely ensure LSEs bring a mix of resources to meet peak demand, which traditionally occurred on weekdays starting in the late afternoon lasting until nightfall. Recent experiences, however, have shown that to be inadequate. Rolling blackouts and near-blackouts in August and September 2020 occurred on weekends and well after sunset.

An increased mix of weather-dependent variable resources, mainly solar and wind, and four-hour battery storage have shifted the overall reliability picture. So has the retirement of coal and natural gas plants throughout the West.

“With the growing penetration of variable energy and use-limited resources, we observe that the 24-hour slice framework can better address reliability than the current MCC bucket structure,” the decision said.

“We have previously emphasized the concern that the MCC buckets are not binding and do not account for energy storage charging needs,” it said. “The 24-hour framework directly addresses energy sufficiency at an individual LSE level by requiring each LSE to provide sufficient excess energy to charge any storage it shows across the 24-hour slices.”

Commissioner Clifford Rechtschaffen said he supported the changes “given what’s happened on our grid the past few years. The mix of resources that we’re employing is changing rapidly, and this has led to new reliability challenges.”

“Ultimately our hope is that load-serving entities will use this new construct … as an opportunity for them to tailor the mix of resources that they procure for their customers’ energy needs to match … the hourly, daily and seasonal variation in their customer load.”

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Developer in ISO-NE Hit with FERC Fine for Capacity Market Fraud

The company behind a Massachusetts gas plant has agreed to pay a $17 million penalty and hand back more than $26 million in profits after FERC found that it misled ISO-NE about the construction timeline of the project and took more than $100 million in capacity payments before it was in operation (IN18-8).

Salem Harbor Power Development received capacity payments from the grid operator for its New Salem Harbor Generating Station north of Boston during the 2017/18 capacity period, despite the fact that the project had not yet been finished or commenced commercial operation, FERC said.

The company continually told ISO-NE that its planned commercial operation date was in May 2017, even as it became clear in internal discussions with construction partner Iberdrola that the project would be significantly delayed as it struggled to find welders. The plant ultimately went into operation in June 2018.

In the investigation, which started as an inquiry by ISO-NE’s Independent Market Monitor before being referred to FERC’s Office of Enforcement, the commission found that Salem Harbor failed to provide complete versions of its critical path schedule to the RTO as required by its tariff.

FERC also said that Salem Harbor made false claims regarding the project’s schedule trajectory and violated its “duty of candor” when it officially became a seller in 2016.

Under the terms of the agreement, Salem Harbor, which is in bankruptcy proceedings, will pay a $17.1 million penalty to the U.S. Treasury and disgorge about $26.7 million in profits, which ISO-NE will distribute to market participants that were harmed by the violations.

New Details Emerge About ISO-NE Role 

FERC’s filing announcing the settlement agreement also contains new information about ISO-NE’s communications with the project’s developers.

The grid operator recently disclosed that it too is under investigation for allegedly helping Salem Harbor avoid the consequences of missing its commercial operation date (COD). (See FERC Investigating ISO-NE over Gas Plant’s Alleged Capacity Market Fraud.)

According to FERC’s investigation, ISO-NE’s director of system planning encouraged Salem Harbor to keep claiming May 31, 2017, as its COD through 2016, even as the company was discussing and ultimately disclosing growing doubts about that timeline.

The director was not named in FERC’s filing, and ISO-NE declined to identify the person in response to a question from RTO Insider.

In October 2016, the company issued a report which listed May 2017 as its COD but acknowledged delays were likely in the narrative section.

“She is fine with our narrative and just encouraged me to put in a few ‘potential’s’ [sic] to make clear this [delay] is not a foregone conclusion,” wrote a regulatory lawyer contracted with the project, after a meeting with the unnamed director.

The director later explicitly acknowledged the likelihood of the operation date slipping to ISO-NE senior management, saying that an asset management company working with Salem Harbor believed there could be delays of several months.

The director wrote that she believed the company was trying to improve its schedule and that she did not want to change the official COD because it would trigger the submission of a demand bid in the reconfiguration auction (ARA3) and force the company to give away its full capacity supply obligation.

“In my opinion, they will likely be late but not significantly,” the director wrote.

The director later told the lawyer that ISO-NE senior management “knows where things stand” and that her office was trying to keep others at the grid operator from “sniffing around,” according to FERC’s filing.

In January 2017, FERC said, ISO-NE’s systems planning team declined to follow up on an employee’s warning about delays in the project’s development timeline.

In February 2017, a representative for Salem Harbor finally acknowledged to ISO-NE that the project’s COD would have to be delayed by months. The company formally changed its COD in ISO-NE’s online system in March, but only after demand bids were due for the reconfiguration auction and it could no longer be forced to shed its CSO.

FERC said that the settlement with Salem Harbor does not assert violations by anyone other than the company, but that the commission “reserves its right to make a determination as to the facts or issues of law that might give rise to any violation by any other such individual or entity.”

ISO-NE Responds

ISO-NE said that it has been cooperating with FERC’s investigation, but it denied wrongdoing and said it has asked the commission to drop its investigation into the grid operator’s role.

The RTO has also changed its market rules since the incident to automatically penalize resources that are not in operation when their capacity payments start.

“To put it bluntly, Salem Harbor defrauded ISO New England and the region,” RTO spokesperson Matt Kakley said.

He said that under the market rules at the time, “the ISO relied on the veracity of input received from market participants in determining the progression of projects in the capacity market.”

Kakley also said that the conversations depicted in the FERC filing between ISO-NE staff and the company lack context.

“Market participants regularly reach out to the ISO for advice on how to navigate complex market rules,” Kakley said. “In this instance, the settlement agreement fails to provide context regarding these conversations, and, at this point, our ability to respond is constrained by FERC’s rules regarding confidential investigations.”

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​MISO, SPP Commit to Replacing Affected System Studies

MISO and SPP revealed more details Monday on their plan to replace their affected system study process with regular interregional transmission planning studies.

The grid operators last month said studies like their current $1.65-billion joint targeted interconnection queue (JTIQ) analysis can furnish more transmission capacity and interconnect generation more efficiently than performing affected system studies and assigning network upgrades to certain interconnection customers. (See SPP, MISO Propose Scrapping Affected System Studies.)

“I think generally the feedback has been pretty good,” David Kelley, SPP’s director of seams and tariff services, said during a teleconference with stakeholders.

The RTOs plan to assign a predetermined, dollar-per-megawatt charge, based on installed capacity, to generation projects in their queues when they fall within the JTIQ-affected system zone. That zone will be determined based on the current affected system study screening criteria of a 5% distribution factor impact threshold on the neighboring system.

The per-megawatt charge will be disclosed when projects enter the queue. While the RTOs say the charge will be adjusted annually based on additional transmission projects, the charge to customers will not change once paid.  

Currently, MISO’s and SPP’s affected system studies process often produces expensive transmission upgrades for prospective generation projects near the seams and interferes with developers’ ability to judge proposed generation’s commercial viability.

“We’re trying to provide that cost certainty upfront,” MISO’s Andy Witmeier said.

However, the grid operators are proposing to divide the JTIQ-affected system zone between MISO Midwest and MISO South. That will mean interconnection customers will pay different charges based on which MISO zone they’re closest to.

Sumit Brar, MISO’s principal engineer of resource utilization, said the transmission costs will be split “proportionally” by MISO subregion. The RTOs’ inaugural JTIQ study only focuses on the northern portion of their seam, where most congestion occurs.

Sequestering MISO Midwest from MISO South continues a planning tactic that MISO has used since adding the South in 2013. Through separate cost-allocation treatment and study deferrals, the grid operator keeps its South region from larger system planning and allocation decisions. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.)

Witmeier said MISO South hasn’t yet seen the prohibitively high interconnection costs necessary for a JTIQ portfolio along the southern seam. He said it doesn’t make sense to have “one gigantic zone” when there isn’t yet a need for a JTIQ study that covers the entire seam. Witmeier said the RTOs might eventually eliminate the two-zone approach if MISO increases the subregional transfer capability between the Midwest and South.

“We can’t opine on how that project will look in the future,” he said. Witmeier explained that the RTOs must currently factor MISO’s subregional constraint in their interregional planning.

“I abhor that we’re creating a new seam within MISO [and] SPP, when the goal should be a more seamless transmission system, as I’m sure MISO and SPP are striving for,” said Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission.

McKinnie said if MISO differentiates Midwest and South projects at the Missouri-Arkansas border, that would be “rough justice” because there are interconnection projects that stand to supply both southeast Missouri and northeast Arkansas.

Stakeholders asked whether the RTOs will reduce the per-megawatt charge when transmission projects fail to reach the finish line. Staff said the charge will only reflect projects that are built.

National Grid Renewables’ Rafik Halim asked how the grid operators would make sure proposed interregional projects aren’t an overbuild of the system.

“Who makes sure no one is trying to gold plate the transmission system on the dime of the interconnection customers?” he asked. “I’m being very frank. This is what everyone is thinking.”   

Witmeier said the RTOs’ staff will continue to share constraints identified by studies with stakeholders and be “upfront with stakeholders about where the overloads” are and which upgrades will help.

Witmeier also said the RTOs cannot implement the affected system replacement until their respective leadership signs off and they receive FERC approval. The grid operators plan to make a filing by the end of the year.

The earliest the proposal could be implemented is MISO’s 2023 queue cycle, which will be kicked off in September, Witmeier said.

Halim said he “strongly suggests” MISO and SPP develop a joint model if they’re going to conduct a JTIQ-style study once every two years.

“We’re all smart people here, all engineers. Can’t we agree on something? If you’re trying to fix the same issues between MISO and SPP, can’t we have the same model?” Rafik said.

“That sounds good in theory. In practice it’s very problematic to implement. We’ve been down that road,” Kelley said. He added that when MISO and SPP tried to develop a singular model a few years ago, it became a “barrier” to effective planning.

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FERC Gives MISO More Time on Software Fix

FERC on Tuesday granted MISO an additional three months on two temporary tariff waivers after software-upgrade delays set back the grid operator’s effort to ensure that regulating reserves take precedence over short-term reserves.

The commission approved extensions on the two waivers until Sept. 28, giving MISO additional time to temporarily override its short-term reserve product’s demand curve and suspend some demand-response resources eligible for fast-start designation. The waivers were to expire Tuesday (ER22-2150).

MISO said it has encountered “unavoidable technical issues, which are attributable to the linear nature of software development.” The grid operator said it has failed twice to upgrade its software and hardware but that it is working with vendors to install a software patch to resolve the issue.

MISO said the extension is “crucial to allow needed flexibility to potentially isolate a time window during peak summer operating conditions” to minimize risk as the upgrades are added. The RTO said it will notify FERC if it completes the software upgrades earlier than the waiver allows.

FERC said MISO “acted in good faith by addressing the software implementation delay as soon as it became evident that MISO was unlikely to meet the June 28, 2022, deadline.” The commission said it had no problem adding 90 days to the limited-scope waivers.

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EQT CEO: Shale Gas Key to National Security, Hydrogen Economy

A massive expansion of hydrogen-ready pipelines built to move Appalachian shale gas to liquefaction plants on the Gulf Coast for export is the key to U.S. and European energy security and addressing global climate change, according to the head of the largest U.S. gas producer.

Toby Rice (CSIS) FI.jpgEQT CEO Toby Rice | CSIS

Toby Rice — a veteran shale gas entrepreneur, CEO of Pittsburgh-based EQT (NYSE:EQT) since 2019 and an early advocate of “blue” hydrogen, produced using methane — says the pipeline expansion would also “set the table” for accelerated hydrogen production that the Biden administration has called for.

In remarks last past week during a lengthy, multi-topic seminar produced by the D.C.-based Center for Strategic and International Studies, Rice said lack of pipeline capacity is limiting shale expansion, particularly in the Marcellus and Utica Shale plays of northern West Virginia, southwest Pennsylvania and southeast Ohio.

He said the world “is running out of time” to address climate change by waiting for the full-blown development of affordable green hydrogen made by electrolysis using solar or wind power because electrolysis is not yet economically viable.

“Access to cheap, clean, reliable energy underpins modern society, everything we do, the pillars of modern life; things like fertilizer, things like concrete, things like steel, these all require energy,” he said.

EQT is one of several unconventional gas producers in the Appalachian region that drill horizontal wells and then fracture oil-and-gas-rich shale.

Nationally, record gas and oil production from shale wells catapulted U.S. production to record levels by 2020, driving down national wholesale gas prices to $2 per 1,000 cubic feet and oil to $40/barrel. Many producers left or were forced to shut down. The industry is now beginning to recover.

Using slides from EQT’s “Unleashing U.S. LNG,” a 56-page presentation the company unveiled in March at CERAWeek 2022, Rice told his CSIS audience that more pipelines would enable producers, particularly in the Marcellus and Utica Shale plays, to greatly expand current production, resulting in enough gas for liquefaction and export while producing feedstock to make blue hydrogen in the U.S.

EQT is working with state governments and heavy industry in the northern Appalachian region preparing to apply for a $2 billion federal grant to create a hydrogen hub, in this case from natural gas with the resulting carbon dioxide sequestered underground. The hydrogen would then be used by nearby industries to decarbonize the production of steel, gasoline and fertilizer that currently rely on natural gas.

“The government’s talking about doing hydrogen hubs everywhere. Here’s how unleashing U.S. LNG can … make that a 1+1=3,” Rice said, introducing his argument to the CSIS audience.

“U.S. LNG is the energy transition for a zero-carbon economy in the United States. Unleashing U.S. LNG would give us the opportunity to rebuild a significant amount of pipeline infrastructure, and the industry is going to pay for that.

“When we build this infrastructure, let’s not think about moving natural gas; let’s build this infrastructure so that it’s hydrogen-ready. That would be incredibly impactful in setting a foundation for the hydrogen economy. Natural gas is going to be a zero-carbon fuel in the future, because we can transform it to blue hydrogen or blue ammonia.”

Rice also argued that LNG would enable Europeans to reject Russian gas. It could also potentially displace coal in India and China, where new coal power plants are still being built. Rice said natural gas power plants have already reduced overall carbon emissions in the U.S.

“The question is, why are people still using coal? The answer is they just don’t have access to natural gas. As resources, if natural gas is a big decarbonizing solution, who’s going to be able to supply that natural gas for the world?

“We believe that we have the resources to grow production over 50 Bcfd for LNG exports, a fourfold increase in what we’re already doing today in LNG exports,” Rice added.

Feasibility of Pipeline Expansion

Joseph Majkut, director of the CSIS energy security and climate change program, interviewed Rice and questioned the feasibility of quickly building the new pipelines he envisions.

“Pipelines encounter multiple challenges, right? You have people worried about stranded assets … [who] don’t want to invest any more in fossil fuels. You also have people whose land is seized because of eminent domain claims, who are not particularly concerned with climate issues but have very local concerns. What’s the basket of reforms that allows us to realize some of this potential without running roughshod over justifiable concerns?” Majkut asked.

Rice agreed that building pipelines or other energy-related projects is extremely difficult, but “we’ve proven that we’re able to build things correctly here in the oil and gas industry,” he asserted. “And nothing we do should be done in a way that we shouldn’t be able to take care of the stakeholders that are involved. We’ve also got … to realize that we need to build stuff in this country. And that’s going to be a big part of the policy [for] environmental justice.”

Fugitive Methane Emissions

Natural gas consists mostly of methane, and leakage from gas wells and pipelines is a major concern of environmentalists because methane is considered a much more potent greenhouse gas than CO2. Rice said EQT is on the way to reducing methane emissions to net zero.

Ben Cahill, a senior fellow at CSIS, asked Rice “to share some details” about how the company is doing that. “The prospect of sending clean U.S. LNG to the rest of the world sounds great. How do we provide certified gas, so we know the methane emission intensity of those cargoes?”

“It’s real simple,” Rice responded. “It’s bullet-proofing our operations and then [providing] radical transparency.

“We know where these emissions are coming from. As a natural gas producer, that biggest source of emissions is a piece of equipment called the pneumatic device. At EQT, we had over 10,000 of these, and we’re replacing every single one of them over 36 months, at a cost of $25 million. That’s going to have the impact of lowering emissions almost over 700,000 tons.”

Majkut noted that reducing emissions at EQT was only part of the solution. “There are emissions associated with liquefaction and shipping,” he said, before Rice asserted, “That’s going to be net zero too.”

Majkut said he believed about 60% of emissions now occur “on the cargo [ship] side.”

Rice agreed. “We’re talking about rebuilding. Probably one of the more challenging things we need to do is rebuild these cargo ships. This is an opportunity for us,” he said in an apparent reference to the industry.

One of the most critical questions put to Rice during the interview came from a member of the audience, Amy Myers Jaffe, a Tufts University professor who had appeared in an earlier, unrelated panel discussion.

“You’re elaborating a plan that’s big buildout, spending billions of dollars. But you’re going to be competing against Saudi Aramco, which already has a plan in place to export [green] hydrogen as ammonia. You’ve got Australia doing a big buildout to export [green] hydrogen as ammonia. And we know that Europe is committed to transitioning [to green hydrogen],” she said.

Noting that U.S. LNG-exporting companies would likely need a 20-year contract with European customers who might baulk at such a long-term commitment in order to pay for the enormous expense of Rice’s plan, she asked why U.S. companies shouldn’t skip exporting LNG and prepare to ship hydrogen or ammonia.

Rice countered that Europe needs gas rather than hydrogen at this point, that LNG in the future will not be a fuel but a hydrogen feedstock, and that focusing on future zero-carbon hydrogen has been an impediment to developing blue hydrogen today.

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PJM MRC/MC Preview: June 29, 2022

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Endorsements (9:10-9:40)

1. Service on PJM for Rate and Waiver Filings under Governing Agreements (9:10-9:30)

Members will be asked to approve an issue charge addressing service to PJM of members’ tariff rate and waiver filings under the RTO’s governing agreements.

The change would require PJM be served when members and interconnection customers file with FERC rate tariff filings, service agreement filings or settlements under the agreements. PJM said the change is needed to ensure the RTO can intervene and participate in such proceedings to protect the interests of members and markets.

2. Operating Committee Charter (9:30-9:40)

Stakeholders will be asked to approve revisions to the Operating Committee charter.

The revised charter adds the phrase “reliability attributes and pertinent conditions” to paragraph 7, pertaining to the committee’s role in reviewing and recommending operating practices and procedures concerning system reliability.

Members Committee

Consent Agenda (1:40-1:45)

B. Endorse proposed revisions to update the process timing for generation deactivations in Part V and Attachment M of the tariff.

Members will be asked to endorse changes to the rules regarding the timing of its reliability reviews for generator deactivations.

PJM says the current deactivation rules are “inefficient and unsustainable” because each response is due 30 days after notification and the tariff does not provide additional time for multiple requests. Under the proposed changes, PJM would study retirements in four batches per year (beginning Jan. 1, April 1, July 1 and Oct. 1) and provide reliability notifications by the end of February, May, August and September.

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Massachusetts Moves Forward with Contentious Net-zero Building Code Proposal

Massachusetts is moving forward with a building energy code proposal that has been broadly challenged by legislators and environmental advocates who say the state is not going far enough to reduce fossil-fuel use in buildings.

The Department of Energy Resources filed draft regulations Friday with the Secretary of State for its update to Massachusetts’ building codes, which includes an update to base and stretch energy codes and a new, specialized opt-in code for net-zero building performance standards. The actions are required by the Next Generation Roadmap climate law passed in 2021.

A straw proposal on the matter released earlier this year was met with widespread criticism, largely because the proposed specialized opt-in code, which is supposed to be the most aggressive option that municipalities can adopt, does not allow cities or towns to mandate that all new construction be fossil-fuel free. (See Mass. Net-zero Building Code Proposal Faces Barrage of Criticism.)

The draft language for residential and commercial construction doubles down on that proposal.

In a summary of the proposal, DOER said that it recognized in drafting the specialized code that many building construction sites and high-rise structures do not currently lend themselves to achieving net-zero status. The specialized code, which municipalities can opt to adopt, allows fossil fuels in new buildings if they also include solar and are “designed with electric service and wiring sufficient for future electrification of space and water heating as well as any combustion equipment appliance loads,” DOER said in a summary of the proposal.

During the public comment period for the straw proposal, many local officials asked that the state allow municipalities to require fossil-free, all-electric buildings.

The stretch code is less ambitious than the specialized opt-in, but it still contains stronger requirements than the base building code. The proposed update to it, which would apply to the hundreds of towns in Massachusetts that have already decided to use the stretch code, increases the energy efficiency requirements for several types of new construction.

By 2024, it would require a Home Energy Rating System score of 45 for all-electric homes and a more stringent HERS 42 score for homes with any use of fossil fuels.

It also sets new standards for a Passive House pathway, adds ventilation requirements and requires that one parking space per home or a minimum of 20% of spaces in a new multi-family parking lot be wired for electric vehicle charging.

DOER will take public comments on the draft language through Aug. 12, with three public hearings scheduled in July and August.

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Cumulative Impacts Analysis a Top Regulatory Priority for CLF, Rep Says

The Conservation Law Foundation (CLF) is working to establish regulatory frameworks that incentivize infrastructure developers to analyze cumulative impacts of projects and protect environmental justice communities, said Caitlin Peale Sloan, vice president for Massachusetts.

An established EJ framework can “empower regulators to reject projects that overburden cumulatively impacted communities,” she said Wednesday during a climate and energy infrastructure panel hosted by the Northeast Energy and Commerce Association.

During the event, energy experts shared stakeholders’ and developers’ perspectives on the challenges of achieving climate targets and building infrastructure to meet those targets.

While CLF supports clean energy deployment, Sloan spoke from stakeholders’ perspective, saying that understanding cumulative project impacts “is critical to assess the impact of the proposed project on different stakeholders.” A cumulative analysis identifies impacts from a proposed project on the project area and the impacts of other actions from the past, present or future that also would affect the project area.

“In this current era, when developers and clean energy businesses really want to do the right thing by EJ populations, you have to use cumulative impacts analysis or you’re still going to wind up disproportionately burdening EJ populations in siting,” Sloan said.

EJ-focused regulations focus on cumulative burdens on EJ populations within the existing “well established framework of siting regs,” she said. CLF’s effort to raise the bar on cumulative impacts analysis seeks to ensure that developers are thinking about EJ communities in the early siting phase. Doing so, she said, could build community support for a project and avoid a “late wave of opposition.”

In Sloan’s view, EJ populations approach stakeholder engagement from a different perspective than under-burdened communities. If a project’s location, design and impacts are “totally locked in,” she said, it inhibits participation from community members.

They have “decades, centuries of well earned skepticism and concern about the intentions that major institutions have for an EJ community,” she said, adding that developers must engage with the community early in the design process, when change is still possible.

Massachusetts’ 2021 Next Generation Roadmap climate law directed the Department of Environmental Protection to issue regulations by the end of this year for incorporating cumulative analyses into the review of certain air permits. DEP will propose draft cumulative analysis regulations by October and take public comment on them through December.

At the beginning of this year, the Massachusetts Environmental Policy Act (MEPA) Office implemented new protocols for EJ community involvement in permitting processes and analysis of EJ community impacts, as directed by the climate law.

The new MEPA regulations represent “the first major changes” to the review process in “many years,” said TJ Roskelley, partner at Anderson & Kreiger.

Speaking during the event from the developers’ perspective, Roskelley called the new protocols “complicated.”

“There’s going to be a lot of learning by doing over the next year,” he said. “As soon as we start to get filings and some feedback from stakeholders and from the MEPA office, I think we will understand this process a lot better.”

The new regulation updates the existing thresholds for what constitutes a basic or extended project review in the permitting process. A review for a project within 1 mile of an EJ community (or 5 miles for projects that affect air quality) must move from a basic 30-day review to include a full environmental impact report (EIR).

Any project that meets the threshold for a full EIR also triggers an enhanced public engagement protocol, which requires notice of the project within a required time frame and “meaningful” outreach to promote public involvement.

Building Support

For Megan Aconfora, public involvement specialist at Burns & McDonnell, stakeholder engagement should change based on the community in which a project is located, but the process must be consistent across communities for developers to find broad success.

Engaging with an EJ community requires a developer to use “different tactics” from other communities, Aconfora said. In sensitive communities, a town hall conversation will not be “productive,” she said, adding that some communities need the developer to build trust.

“Sometimes trust means not immediately rolling in and talking about your project, but just showing yourself as someone that they can communicate with,” she said.

While early community engagement is critical for large-scale energy infrastructure projects, Joe Rossignoli, founder of the consulting firm Ross Emergent, said it’s possible to “design support into a proposal” by “making greater use of the existing transmission system.”

That approach might include, for example, using storage as a transmission asset to ensure bulk system reliability on lines that traditionally would be constrained to prevent outages.

“These devices allow lines that would otherwise be security constrained for N-1 contingencies to flow at their nominal capability,” he said. The instantaneous response, he added, prevents the line from experiencing a thermal overhold.

Another option is to take a fresh look at limits on the amount of power that can flow over a right of way. Doing so, Rossignoli said, would require a review of the Northeast Power Coordinating Council rules that permit the evaluation of extreme consistency violations based on the historic or projected variability in the use of lines on interregional corridors.

“What’s clear from recent developments is that cutting new rights of way to get customer access to power supply and in neighboring regions just isn’t doing the job,” Rossignoli said.

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Interconnection Rulemaking Wins Support but Funding Questions Remain

ARLINGTON, Va. — Attendees at the Infocast Transmission & Interconnection Summit last week greeted FERC’s June 16 proposal on interconnection as long overdue but expressed frustration that the commission had failed to address the issue of participant funding.

The commission unanimously approved a Notice of Proposed Rulemaking that would replace the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies (RM22-14). The commission also proposed more stringent financial commitments and readiness requirements for interconnection customers, which it said would discourage speculative interconnection requests. (See FERC Proposes Interconnection Process Overhaul.)

“Those are great fixes — going to help streamline everything,” said Brian C. Drumm, director of regional policy and RTO engagement for ITC Holdings. “But it’s also, I think, somewhat of a Band-Aid approach. … It’s not addressing the problem of this lack of transmission and this increasing cost that interconnecting generators are being asked to bear.”

Kevin McAuliffe, director of PJM and Northeast markets for nFront Consulting, said it is clear that grid planners can’t rely on the generator interconnection process to build out the system and that planners need to be more proactive in considering what is required to meet decarbonization goals. “As you get more and more generators in [the queue], it requires more and more big backbone upgrades to rebuild the system. And that’s hard for a generator to accommodate,” he said.

“One thing that is distinctly omitted from this NOPR is any way to address the deficiencies in the existing participant funding model,” said Tyler H. Norris, vice president of development for Cypress Creek Renewables. “We hope to see FERC address it in another venue.”

The NOPR said the existing serial study process may be unjust and unreasonable because an interconnection customer that triggers a network upgrade can be saddled with its entire cost even though it creates additional capacity for other interconnection customers that don’t share in the bill.

FERC proposed requiring transmission providers to allocate network upgrade costs among interconnection customers in a cluster based on the degree to which each generating facility contributes to the need for the upgrade.

But the 407-page NOPR includes just two brief mentions of participant funding, including a footnote to its observation that “although the crediting policy in the pro forma LGIP [large generator interconnection procedures] requires that the interconnection customer is ultimately reimbursed for the cost of the network upgrades, the large upfront network upgrade cost allocation may render a proposed generating facility economically non-viable, such that the interconnection customer is forced to withdraw from the interconnection queue.”

In a report to clients Monday, ClearView Energy partners said it expects FERC to issue an additional rulemaking addressing cost allocation beyond shared interconnection costs “as well as some of the mechanics of generator interconnection financing.”

Eliminating ‘Chicken’

Other aspects of the rulemaking also prompted comments during the three-day conference.

Arash Ghodsian, senior director of transmission and policy for EDF Renewables, acknowledged that he has a different perspective on the queue process than he did when he was a transmission planner for MISO.

“When developers used to come to us and say, ‘We need queue reform. We need efficiency,’ we used to push back and say, ‘Well, you know, it took us it took us a decade to get to where we are today.’ Now being on this side of the fence, I’m one of those who’s pushing [for] changes.”

Anton Ptak, director of transmission and interconnection for EDF, said planners should use the location of generators in the queue as a guide to the most attractive areas for siting. “If you can use that information in your planning process — to help guide where to put these large new lines or major rebuilds or reconductors — I think that will significantly help. It’ll take a little bit of … the game of chicken out of the interconnection process,” he said.

Several speakers praised FERC’s proposal to eliminate the “reasonable efforts” standard and penalize transmission providers $500/day for failing to meet study deadlines.

“I think that timelines for TOs are helpful if they have the resources to meet those timelines,” said Sarah Bresolin, director of government and regulatory affairs and wholesale markets policy for ENGIE North America. “That’s something that we struggled with at both the transmission and the distribution level. So some level of accountability there is helpful.”

FERC ‘Catching Up’

“I do feel like in some ways, FERC is catching up to what we just implemented in Duke territory [in North and South Carolina] with respect to the transition to cluster studies,” said Cypress Creek’s Norris.

Duke Energy (NYSE:DUK) implemented its first-ready-first-served, cluster-based process last year after it was approved by FERC in August (ER21-1579).

Kenneth Jennings, general manager of renewable integration and operations for Duke, said the company held stakeholder meetings for about nine months before it began drafting tariff changes.

“Once we did draft tariff changes, we shared those tariff changes with stakeholders and asked for feedback. Whenever we could incorporate recommendations from interconnection customers, we did it — as long as it didn’t compromise what we thought the integrity of the process was or reliability in any way.”

Jennings said interconnections become a problem “where there’s robust incentives for development.”

“When PJM started the RPM [Reliability Pricing Model] capacity market, there were immediate interconnection issues right away. … In North Carolina, the incentives were around solar; there was kind of this weird intersection between where the cost of solar declined and the avoided cost rates for [Public Utility Regulatory Policies Act] projects had reached the point where the cost was lower. And all of a sudden, we had a lot of activity. Initially, it wasn’t too bad because we had headroom in our system. … We ended up having this large influx of interconnection requests that we couldn’t get processed. And at some point, we were getting about four times the [number] of requests that we could process in a year.”

Southern Co. Reluctant to Abandon Serial Approach

Not everyone at the conference was ready to endorse FERC’s proposals, however.

Corey Sellers, transmission policy and services manager for Southern Co. (NYSE:SO), said his company supports the first-ready, first-service concept. “We were already looking at potentially some changes that would move us in that direction,” he said.

But he said the company is concerned about abandoning the serial process for cluster studies.

“We’ve been pretty efficient in being able to process serially our requests,” he said. “We were looking at something a little bit more of a hybrid. … Our biggest concern is the continual restudies that you see when you have a cluster process. Not sure exactly how that would work for us.”

PJM Interconnection Filing

PJM proposed changes to its interconnection process — which largely mirror FERC’s proposal — two days before the NOPR (ER22-2110). (See PJM Files Interconnection Proposal with FERC.)

The overwhelming support that members gave the proposed rule changes “was a PJM stakeholder success story,” said Erik Heinle, senior assistant people’s counsel for federal affairs and wholesale markets for D.C. “When PJM began this process back in late 2020, it was a very acrimonious process. … There was some serious disagreement about how we get there and, understandably, very frustrated generators who want to get on the system.”

He acknowledged that the RTO has additional work to do, which will be led by the Interconnection Process Reform Task Force.

Bhaskar Ray, vice president of interconnection and development engineering for Q CELLS USA, also praised PJM for “a very well engaged stakeholder reform process.”

But he said it’s unclear how PJM will handle the transition to the new rules. He also said his company also has concerns over how PJM would respond if Q CELLS’ lease options — acquired to demonstrate site control — expire before studies are completed.

Ray also said the company is seeing “a lot of cost overruns.

“This is an ongoing issue. I think one way to circumvent the problem would be to do more quarterly financial expenditure forecasts, because it’s very hard on developers to get these overruns of 50 [to] 60%.”