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August 30, 2024

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Connecticut Environmental Regulator Launches EJ Advisory Council

The Connecticut Department of Energy and Environmental Protection (DEEP) launched the state’s Equity and Environmental Justice Advisory Council with an inaugural meeting Tuesday.

Creation of the council “reflects a priority within DEEP and the Lamont administration to center equity and environmental justice in our work, especially when it comes to addressing environmental quality, energy equity, climate change mitigation and resiliency, health disparities, racial inequity and current and historic environmental injustice,” Commissioner Katie Dykes said at the meeting.

Dykes will co-chair the 18-member council with Mark Mitchell, associate professor of climate change, energy and environmental health equity at George Mason University.

“Historically, non-white communities, particularly African American communities, are exposed to a number of different environmental and social traumas, so cumulative risk is something that you will hear a lot as we move forward,” Mitchell said.

The Governor’s Council on Climate Change recommended formation of the environmental justice (EJ) group, and Gov. Ned Lamont authorized it as a part of DEEP in an executive order in December.

Among the council’s priorities will be to advise DEEP on how to incorporate EJ considerations into its programs, policies and activities. It will also be responsible for creating mechanisms for EJ communities to participate in DEEP’s work areas and developing a model plan for community engagement and outreach.

The council includes representatives from the Connecticut departments of public health, housing, transportation, and economic and community development. Their presence will “strengthen and inform” the council’s work and “help incorporate environmental justice principles and priorities in the work of those agencies,” Dykes said.

Initial work plan priorities will include establishing areas of DEEP’s authority that the council will focus on and the structure for their discussions. Dykes suggested the council form subcommittees that can address DEEP’s wide range of programs and responsibilities, such as land resources, environmental quality, climate mitigation and energy equity.

The council may also consider convening community meetings, particularly in EJ communities, to collect public comments on the topics covered by subcommittees, Dykes said.

Rep. David Michel (D) congratulated the council members on their appointments during the meeting and asked them to consider creating a subcommittee on energy facility permitting.

“Considering that today’s language in statutes makes it hard for DEEP to turn down a permit for a new polluting facility, or even an existing facility, permitting should definitely be a focus of the group,” he said. The legislature has tried to address the issue, he said, adding that the council’s work could support legislators’ ongoing efforts through, for example, better mapping of EJ and distressed communities and the facilities that cause pollution.

DEEP is currently facilitating a two-year project, as recommended by the governor’s climate council, to develop an EJ screening tool that identifies environmental and public health indicators across the state.

Dykes said the department anticipates scheduling quarterly council meetings, with the next one planned for September.

Member Priorities

The council took time during the meeting to get to know each other and share their priorities.

Sharon Lewis, executive director of the Connecticut Coalition for Environmental Justice, said the statewide coalition has a wide focus on environmental issues, but it is “majorly concerned” about zero waste and what Connecticut will do about it.

“Overall, we want to see an equitable sharing of the benefits and the burdens of the environment and meaningful involvement of those most impacted by the decisions that are implemented and affect their well-being,” Lewis said.

Taylor Mayes, an organizer for the Black Environmental Activist Movement, concurred with Lewis, saying that her work focuses on “making sure that black communities throughout Connecticut have the same access and opportunity to environmental assets and benefits as the rest of the state does.”

At the grassroots coalition CT Equity Now, Katharine Morris works to build bi-directional engagement with community members.

“I want to engage with them in a way that is sustainable so that they believe in us to actually represent their needs,” Morris said. CT Equity Now focuses on initiatives related to ecological health, sustainable food systems, clean transportation, transitioning to clean energy and “facilitating natural remedies to long-standing pollution impacts,” she said.

Maisa Tisdale, president of the Mary and Eliza Freeman Center for History and Community, said the center is solely focused on preservation-based equitable development in the state.

“The future of our community is directly and significantly impacted by remediation of brownfields,” she said. The remediation of shuttered utility brownfield sites and their return to communities for equitable development could represent “a form of reparations.”

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NJ Solar Sector Calls for Speedy Grid Modernization Plan

Solar developers embraced a new report by the New Jersey Board of Public Utilities (BPU) on how to modernize and upgrade the state’s power grid to handle the expected dramatic rise in energy from wind and solar projects, but they told a public hearing Monday that the state needs to act faster.

The 102-page report, compiled for the BPU by consultant Guidehouse, of Lawrenceville, offers nine recommendations on how to improve what solar developers see as an aging grid that has limited capacity on the grid, which in some areas of the state can’t accept new interconnections. (See Solar Developers: NJ’s Aging Grid Can’t Accept New Projects.)

The suggestions in the report, which was released Friday, include streamlining the interconnection process and improving the state’s hosting capacity maps, which report how much generation can be added to a circuit. The report also suggested enabling developers to get a “pre-application study” that would allow them to see the available connection capacity in advance, rather than late in the development cycle.

Speakers from the solar industry, while welcoming the report, said the gravity of the situation requires additional moves.

“You’ve identified all the right things. We’re with you; we want to work and collaborate on this and move forward,” Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, told the hearing. “Obviously, time is of the essence.

“My only comment would be is if we could have some kind of a parallel track where we could, as a triage measure, put money into opening some of the existing circuits that have been closed, where it’s obvious, cost effective,” he added. That would enable the industry to “open up some of these markets and will take a lot of pressure off the situation.”

Lyle Rawlings, a solar developer and founder of the Mid-Atlantic Solar Energy Industries Association, echoed the call for the BPU to move quickly.

“We urgently need ventures near-term that will keep circuits open and reopen ones that are currently restricted,” he said.

Clean Energy Surge

The hearing, the fourth to collect stakeholder input on current distribution grid interconnection policies and processes and potential improvements, was the last in the fact collection stage, which began in October. While stakeholders can submit written comments until July 19, the release date of the final report has not yet been set.

The effort is one of several New Jersey initiatives underway aimed at preparing, upgrading and improving the grid for the capacity expansion expected from the state’s advancing solar and wind sectors. New Jersey’s first community solar projects came online last year, and the state reshaped its solar incentive program. (See New Jersey Shoots for Key East Coast Wind Role.)

The state has so far approved three offshore wind projects — the 1,100-MW Ocean Wind 1, 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores — in two solicitations, and expects the first project to be operating in 2024. A third solicitation is planned for early 2023, and the state expects to approve further projects that will increase the state’s wind capacity to 7,500 MW by 2035.

The BPU is close to finishing a solicitation process for suggestions on how to best connect the offshore wind projects to the grid, which attracted 80 proposals. (See FERC Approves PJM-NJ Transmission Agreement.)

And the state legislature is considering a bill that would levy a fee to generate millions of dollars to modernize the grid. At a hearing of the Senate Energy and Environment Committee in May, developers said they wait for months, even years, to get projects connected, and sometimes the connection never happens.

Yet those delays are not unique to New Jersey. The U.S. Department of Energy this month launched an initiative, Interconnection Innovation eXchange (I2X), designed to identify and develop solutions to speed up the interconnection of clean energy projects. (See DOE Initiative Aims to Make Interconnection ‘Simpler, Faster, Fairer’.)

In April, PJM stakeholders overwhelmingly endorsed a plan for a new interconnection queue process amid concern over delays and heavy volume.

Abraham Silverman, strategic policy counsel for the BPU, opened Monday’s hearing by saying that addressing the grid issue is “absolutely critical.” He added that the PJM queue problems show what happens when the sector doesn’t get “the interconnection right.”

“Projects get delayed. … The energy transition slows down,” Silverman said.

Plans to Streamline, Fast Track

The BPU report, and its presentation at the hearing, said there are a variety of opportunities to streamline the application process through which new interconnections are sought, including updating the forms and resolving the fact that each utility has a different system.

The report also suggested that the industry adopt a new, uniform application software and platform system, and introduce new fees on Level 1 projects — smaller projects that are not currently required to pay fees — to pay for the upgrades.

Other proposals in the report include a recommendation that utilities adopt a uniform system of hosting capacity maps, which report how much spare capacity is available in different areas of the state. The current maps are “inconsistent,” resulting in the “quantity of closed circuits potentially being overestimated by stakeholders,” the presentation said.

“Stakeholder support for capacity hosting maps is strong in New Jersey,” the presentation said. “But the maps provide value only when updated with current data and relevant information regarding equipment costs.”

The report also concluded that that “there is no way to accelerate interconnection projects” under the state’s current system and no “fast track” process to speed up simpler projects. There is also no pre-application process that would enable a developer to learn in advance the availability of grid capacity and likely upfront costs, according to the report, which recommended such a process be implemented.

The report also suggested the state use the updated version of the recommended rules and regulations drafted by the Institute of Electrical and Electronics Engineers that govern interconnection and operability systems. And the report suggested that the state implement a systematic process that would “establish numerical cost and capacity thresholds” that would evaluate and determine, for example, whether an upgrade simply benefits certain distributed energy resources or has a benefit to all customers.

Reaching Energy Goals

Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), said the report reflects the feedback that his members have presented to the consultant. But he added that the “key consideration is not just identifying opportunities to improve interconnection, but moving forward with these types of reforms with the pace and scale necessary for New Jersey to achieve its goals.”

“If we don’t make major strides on interconnection reforms in the next few years, it will be impossible to achieve New Jersey’s aggressive clean energy goals,” Elias said. He added that “there’s plenty of evidence that the status quo is not tenable.”

Elias also called for the BPU to create “a clear timetable for how [it] will evaluate how grid modernization costs can be spread over a broader set of beneficiaries.”

“I think moving to a system where developers pay an appropriate portion of upgrade costs and the remaining costs are socialized among all customer classes benefiting from that upgrade would help bring online much more clean energy on New Jersey’s grid,” he said.

Eric Miller, director of New Jersey energy policy for the Natural Resources Defense Council, said addressing interconnection issues will be key to reaching the goals in the state Energy Master Plan, and said the organization is “pleased” with the way the report is going.

“We recognize the significant importance of kind of tackling interconnection first, and we think, you know, the recommendations so far … make significant progress on this front,” he said.

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DOE Launches $500M Project to Put Clean Energy on Mine Lands

A 7-MW solar project now stands on land in Strafford, Vt., that was once the site of the largest copper mine in the U.S., and the Department of Energy is planning to use $500 million from the Infrastructure Investment and Jobs Act to put clean energy on similar former mine lands across the country.

The DOE’s vision for the Clean Energy Demonstrations on Current and Former Mine Land Program is outlined in a request for information released Wednesday. The program’s goal is to fund two to five demonstration projects in different parts of the country. At least two of the projects must be solar, the RFI says, but the DOE’s definition of “clean energy” also includes geothermal; direct air capture; fossil fuel generation with carbon capture, utilization and sequestration; energy storage, including pumped hydro; and advanced nuclear.

Hybrid projects combining two or more of the designated clean energy technologies are also eligible for the program. Technologies not eligible include bioenergy, wind, hydropower (other than pumped hydro) or recovery of critical minerals, and the federal funds must be matched, dollar for dollar, with nonfederal funds.

“Developing clean energy on mine lands is an opportunity for fossil fuel communities, which have powered our nation for a generation, to receive an economic boost and play a leadership role in our clean energy transition,” Energy Secretary Jennifer Granholm said in a press release announcing the RFI.

A recent report from the Environmental Protection Agency identified 17,756 mine land sites, totaling 1.5 million acres, which, if fully developed, could provide close to 90 GW of power. The report highlights the Elizabeth Mine solar project in Vermont as an example of clean energy development on previously contaminated mine lands. The project has cut carbon dioxide emissions by about 6,000 tons and produces enough electricity per year to power 1,200 homes, the report says.

The RFI also lays out key criteria DOE will apply for project selection. Projects should have “a reasonable expectation of commercial viability and also demonstrate the ability to lower barriers for future clean energy projects to access private sector financing,” the RFI says.

Economic development is another key criterion, with the DOE prioritizing projects that will create the most jobs, direct and indirect, and boost local economies in frontline fossil fuel communities. Projects will also be evaluated on their estimated levelized cost of energy, the GHG emissions produced by energy generation and how long it will take to complete them.

Beyond job creation, the RFI also puts a heavy emphasis on environmental and energy justice. The RFI defines energy justice as “achieving equity in both the social and economic participation in the energy system.” For example, the RFI calls on projects to “increase parity in clean energy technology access and adoption.”

With reasonable completion times a high priority, the RFI also acknowledges the considerable challenges mine land projects may face in terms of permitting and having to mitigate existing environmental hazards at mine sites. The RFI asks for input on how the topography or subsurface condition of mine lands might affect a site’s suitability for clean energy development. Information is also requested on federal, state and local permitting requirements and potential obstacles in existing regulations.

The goal is to provide replicable models and best practices for future projects. “The selected projects will chart a course to navigate federal, state and local rules and regulations for siting and grid interconnection, mine remediation, post-mining land use, environmental safety and other important processes to successfully develop and operate clean energy projects on current and former mine land,” the DOE announcement said.

The DOE added it is working with its national labs to gather data on existing clean energy projects on mine lands to help identify “promising sites” for clean energy development. The comment period on the RFI will close on Aug. 15, and the DOE is planning a series of webinars that “will collect region-specific perspectives on the challenges and opportunities of clean energy development on mine land.”

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Reduced Driving a Hard Sell in GHG Plan, CARB Finds

Reducing the number of miles driven by residents is one of California’s strategies for reducing greenhouse gas emissions, but state officials concede the goal will be difficult to accomplish.

The strategy appears in the California Air Resources Board’s climate change scoping plan, which lays out a pathway for the state to reach carbon neutrality.

A draft version of the plan, released in May, proposes reducing per-person vehicle miles traveled (VMT) by 12% by 2030 and 22% by 2045, as compared to 2019 levels.

During a CARB public hearing last week on the draft scoping plan, board member Diane Takvorian called for more aggressive VMT reduction targets: 25% by 2030 and 30% by 2035, compared to 2019 levels.

Takvorian asked CARB staff for further analysis of funding public transit versus spending money to get drivers to switch to ZEVs. Takvorian pointed to free-ride programs in the San Diego area that have helped boost transit ridership.

The San Diego Metropolitan Transit System (MTS) offered free rides in September 2021 to riders who used MTS’ new fare collection system. MTS’ total ridership that month was 4.92 million, 14% higher than August and 4% higher than in October, when the free-ride program was discontinued.

MTS is also offering free youth opportunity passes as a pilot program. In May, the first month of the program, the transit system’s number of youth accounts surged to 16,374, a 74% increase from the prior month, according to figures provided to NetZero Insider.

“We’re a car culture. We know how to help people buy cars,” said Takvorian, who represents the public on the CARB board. “What we don’t know how to do is change the culture so people ride public transit. We need to work on that more.”

Rajinder Sahota, CARB’s deputy executive officer for climate change and research, noted the challenges of reducing VMT.

“The problem is we’ve modeled very aggressive VMT targets in almost every scoping plan we’ve done,” Sahota said. “We’ve delivered on none of those. And so this is an entrenched problem in the scoping plan.”

Board member Daniel Sperling also expressed pessimism about the scoping plan’s VMT reduction goals.

“Ain’t gonna happen,” Sperling said. “It’s failed, and it’s going to continue to fail because of the land use patterns we have, the car-centric transportation system we have, the sprawl we have.”

Transit is already heavily subsidized and its share of passenger miles was falling even before the pandemic, said Sperling, who is a founding director of the Institute of Transportation Studies at the University of California, Davis

Making Transit Attractive

Gov. Gavin Newsom issued an executive order in September 2020 calling for all new cars sold in the state to be ZEVs by 2035. But even if the target is met, internal combustion cars will remain on the road for some time.

The draft scoping plan outlines a number of measures to reduce per-person VMT, such as increasing the affordability and convenience of public transit, so that it becomes a more attractive alternative to driving.

The plan proposes expanding infrastructure for active transportation, such as walking and biking, and building more housing in “transportation efficient” areas.

The draft scoping plan explores four scenarios for California to reach carbon neutrality. The scenario selected as the preferred alternative would bring the state to carbon neutrality by 2045. (See Draft Plan Seeks Calif. Carbon Neutrality by 2045 and Critics Tear into CARB Draft Climate Change Plan.)

The CARB board took no formal action during last week’s two-day hearing on the scoping plan. Board members weighed in on certain issues and asked staff for further analysis of topics such as VMT reduction.

More Cars per Household

CARB also released a report in June taking a closer look at VMT reduction efforts. Senate Bill 150, passed in 2017, requires the agency to prepare a report to the legislature every four years on the progress the state’s metropolitan planning organizations have made in reducing GHG emissions. CARB released the first SB 150 report in 2018.

“California is still not reducing GHG emissions from personal vehicle travel,” the new report said. “Per capita GHG emissions and per capita VMT continued to increase, though more slowly than in the 2018 progress report.”

The report found that California residents are driving to work more and carpooling less. The percentage of people who walk or bike to work, which was already small, is shrinking. At the same time, the number of vehicles per household is increasing and roadways are expanding, according to the report, which includes data through 2019.

Land use patterns are another factor contributing to VMT, the report said. People who live close to work, shopping and recreation don’t need to drive as much.

The report found that development in the state has become more compact since 2005, with the exception of the San Joaquin Valley, where development has become more spread out. Even where development is more compact, residents still can’t walk to “key destinations,” the report said.

The report said that the state must move beyond simply planning to reduce greenhouse gases and VMT.

“No matter how robust, regional plans alone cannot reduce emissions,” the report said. “It is critical that the state, including the legislature, focus attention on authorizing and funding strategies and on providing other policy tools that support implementation.”

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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.