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October 10, 2024

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NJ City Calls for Delay to Ocean Wind 1

Ocean City, through which transmission from the first offshore wind project in New Jersey would run, argued Friday that the Board of Public Utilities (BPU) should delay the project while an administrative hearing and environmental studies of the line’s route are conducted.

The city made its argument during an online public hearing on a petition filed by developer Ørsted asking the BPU to approve an easement for the line to run underground across land developed with state Green Acres money, which funds the development of parkland and natural areas.

Ørsted is seeking approval under a new law passed by the legislature last year and enacted in July that gives the BPU authority to over-ride local government officials in land-use questions concerning offshore wind projects if the board finds that the land is “reasonably necessary” for the project’s construction.

The case is the first test of the law, and the dispute over the easement is one of the most prominent challenges so far for the 1,100-MW Ocean Wind 1, the first of three offshore projects approved to date by the BPU.

Dorothy F. McCrosson, solicitor for the city, questioned the legitimacy of the law, saying it has “not yet been tested in the courts” and said the petition should be heard by the Office of Administrative Law.

“It remains to be seen whether it will survive judicial scrutiny,” she said.

Ørsted is seeking a 30-foot-wide easement running the length of the city’s main island, which is about 8 miles long, for a 275-kV cable that will connect Ocean Wind’s turbines, about 15 miles offshore, to the PJM grid at a substation, sited on a closed coal-fired power plant in neighboring Upper Township.

Ocean City opposes the project, which was approved in 2019, as do local residents, who say the nearly 100 turbines will tarnish their ocean view. Also opposed are commercial fishermen, who say it will hurt their ability to fish, and tourism interests, who fear fewer visitors will come to enjoy a shoreline with turbines on the horizon. (See Ørsted NJ Wind Project Faces Local Opposition.)

Pristine Beach and Wetlands

BPU President Joseph Fiordaliso told speakers, however, that the hearing focused only on the narrow issue of whether the easement was reasonably necessary. Aside from attorneys from Ocean City and Ørsted, the only speaker was the director of the New Jersey Division of Rate Counsel, Brian O. Lipman. As in a court trial, each speaker was allowed an opening statement and time to rebut other speaker’s comments.

The BPU made no decision on the issue Friday, and Fiordaliso said the board will evaluate all the evidence presented and make a decision at a future, as yet undetermined, date.

McCrosson noted that the U.S. Bureau of Ocean Energy Management (BOEM), which last week released a draft environmental impact statement (DEIS), the National Marine Fisheries Service (NMFS) and Army Corps of Engineers are working on environmental impact statements.

“Any one of these agencies might determine that the environmental impact of the proposed route through Ocean City is unacceptable,” McCrosson said. “In which case, the easements would not be reasonably necessary. Waiting until the environmental impacts can be addressed and understood would be prudent.”

She argued that Ocean Wind 1 could avoid the conflict with Ocean City if it opted to send the transmission through a different route, which would go through nearby Egg Harbor instead. She said the route would present no disruption to Ocean City, but Ørsted had dismissed it earlier because it would be more expensive.

“The overwhelming benefit of utilizing the Egg Harbor route is the utter lack of disturbance to the citizenry of Ocean City,” McCrosson said. “The city’s pristine beach and wetlands would not be disturbed. The streets would not be excavated.”

But attorney Gregory Eisenstark, representing Ocean Wind 1, said the developer has provided extensive testimony on the environmental and construction reasons why the Egg Harbor route was not suitable.

“The impacts to Ocean City and its residents will be minimal,” he said. “The line will be underground. Once the construction is completed, you won’t see it and you won’t hear it. And quite frankly, it will be no different than the underground facilities that are already in Ocean City.

“I suggest to you that Ocean City’s feigned objection to the route that we’ve selected has nothing to do with the actual onshore route. But it has to do with Ocean City’s overall objection to offshore wind.”

Eisenstark said the cost of the different routes evaluated had no bearing on the hearing because Ørsted will pay for it as part of its bid for the project and not ratepayers. He added that the “reasonable necessity” standard doesn’t mean that the easement has to be “absolutely necessary” to the project.

“It doesn’t mean it’s the only alternative,” he said. “It doesn’t even mean it’s the best alternative. It just means that the project evaluated different alternatives, and the alternative it has proposed is a reasonable one. It doesn’t have to be the best one. It doesn’t have to be the lowest-cost one.”

Appraisal Offer

The three offshore wind projects approved by the BPU so far total about half the state’s target of 7,500 MW by 2035. The other two, the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores, were approved in June 2021. The state expects the first of three more solicitations to begin early in 2023. (See NJ Awards Two Offshore Wind Projects.)

BOEM’s DEIS concluded that the project would not have a major impact on most of the 19 environmental and related categories scrutinized in the report. But the 1,408-page report did find that it would likely have a significant, and in some cases major, impact on marine navigation and vessel traffic. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project).

Eisenstark said Ørsted has discussed the needs of the project with Ocean City officials for three years. The developer filed its petition asking for the easement after sending a formal letter on Aug. 11 seeking the town’s blessing for the easement. Ørsted also obtained an appraisal of the value of the easement and offered to buy it for 10 times the amount, but it has not received a response from the city, he said.

“Ocean Wind would prefer to reach a voluntary agreement with Ocean City,” he said. “But unfortunately, we have not been able to reach an agreement.”

In May, the New Jersey Division of Rate Counsel told a hearing on the plan that it had concerns about the Ocean City route and believes there was an acceptable alternative that would be longer but would result in fewer disturbances.

But on Friday, Rate Counsel Lipman said he would like to contribute to the evaluation of the easement but could not because the division had not been able to obtain sufficient insight. He questioned the process behind the hearing.

“We have not had the opportunity to fully probe that issue,” he said. “There was no discovery in this matter. We asked Ocean Wind if they would ask answer some questions, and they did answer some of our questions. But not all of our questions. And they didn’t have to because there was no discovery in this process.

“Ocean City raises a number of issues that, quite frankly, we would have liked to have resolved if we’d known about them through discovery,” he said. The cost of each route is relevant, and that is recognized by the state Supreme Court so that the board can determine whether it is reasonably necessary for the developer to opt for one route over another, he said.

“I understand this is the first case of its type. And so the process was going to be somewhat different,” he said, adding, “We don’t believe there’s sufficient evidence in the record for that decision to be made.”

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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.