FERC granted an Oklahoma solar project a 90-day extension of its commercial operation deadline while rejecting an Illinois wind project’s request for a waiver, saying the developer failed to make its case for relief.
The commission on Thursday granted Recurrent Energy’s 120-MW North Fork Solar Project in Kiowa, Okla., a 90-day extension of its required commercial operation date (COD) (ER23-737).
North Fork’s generator interconnection agreement with SPP and Western Farmers Electric Cooperative requires commercial operation by May 1, 2024, which was extended from the original COD of December 1, 2019. The company said it needed a 90-day extension, to July 30, 2024, to align the COD with the mechanical completion date provided by North Fork’s engineering, procurement and construction (EPC) contractor and to allow a 90-day period between mechanical completion and the COD, as required under North Fork’s power purchase agreement.
Neither SPP nor Western Farmers opposed the waiver.
North Fork said it has spent $7.7 million developing the project and expects to spend an additional $11 million by the time construction begins, including payments to the EPC contractor, developer fees and financing costs. It has secured land rights for 1,920 acres for the project, which will interconnect at Western Farmers’ 138-kV Snyder Substation.
North Fork has a 15-year PPA with the Oklahoma Municipal Power Authority (OMPA) for the full output of the project. The PPA requires the project to reach commercial operation by May 31, 2024, so that OMPA can claim capacity credits for the summer of 2024. North Fork would be liable for liquidated damages if it misses the deadline.
“Accordingly, North Fork states that it is commercially incentivized to achieve commercial operation as soon as possible,” FERC said.
North Fork said its EPC contractor has provided an estimated mechanical completion date of mid-March 2024, which would precede the initial synchronization and beginning of test sales.
Waiver Rejected
In a second order, the commission rejected a request by ZEP Grand Prairie Wind, a proposed 150-MW project in Illinois, to extend its COD from November 2025 to February 2027 because of delays caused by the COVID-19 pandemic (ER23-137).
ZEP’s generator interconnection agreement with MISO and the city of Springfield, Ill., would be terminated if the project does not reach commercial operation by November 2025.
Developer UKA North America said it had recalled its land agents responsible for negotiating property rights for the project site and interconnection rights-of-way in response to the Illinois governor’s March 2020 executive order requiring all non-essential employees to remain at home because of the COVID pandemic.
The company also cited supply chain problems that arose during the pandemic, saying key components that previously took nine to 12 months to receive are now taking 18 months or longer.
ZEP Wind said that it has spent more than $4 million on the project and obtained 100% site control and more than 85% of the transmission rights-of-way required. Nevertheless, it said will be unable to reach commercial operation by its 2025 deadline.
The commission said ZEP Wind “has not provided any details regarding whether any components for the project are delayed, the estimated time for their delivery, or whether and how any such delay affects its ability to achieve commercial operation by November 15, 2025.”
The commission said it would reconsider the waiver request if ZEP Wind provides more detail.
FERC on Thursday also upheld five prior rulings that had been subject to rehearing requests:
The commission addressed arguments raised on rehearing of its Oct. 20, 2022, order accepting Henderson Municipal Power and Light as a transmission owner in MISO and allowing Henderson to recover its revenue requirement for transmission facilities (ER19-776-002, ER19-809-002). (See FERC Rules Kentucky Muni Can Remain a MISO TO.)
The commission addressed requests for rehearing of its Sept. 9, 2022, order accepting two unexecuted generator interconnection agreements, which assigned to SPP interconnection customers the costs of a network upgrade (ER22-2371-001, ER22-2372-001).
The commission rejected Tenaska Clear Creek Wind’s request for rehearing of its Sept. 9, 2022, order, which found that the assignment of certain network upgrade costs was just and reasonable (EL21-77-003). The order also denied a motion for stay. (See FERC Rules in Three SPP Disputes.)
FERC sustained the result of its Oct. 7, 2022, order denying Southwestern Public Service Company’s complaint alleging that SPP violated its tariff by setting the cleared energy award for SPS’s Hobbs generating facility to zero when SPP settled the day-ahead market for Feb. 17, 2021 (EL22-30-001).
WASHINGTON — The sixth meeting of FERC’s Joint Federal-State Task Force on Transmission, held Wednesday, looked into how the grid can be better protected against physical attacks, which have been on the rise recently.
“There are well over 50,000 high-voltage substations across North America, and more than that if you include those that only support the distribution system,” NERC CEO Jim Robb said at the meeting, held concurrently with the National Association of Regulatory Utility Commissioners’ Winter Policy Forum. “That’s a tremendous amount of infrastructure to think through how to protect responsibly, and to really think through the tradeoffs that need to be made between risk and consequence and the investments that you make between protection and prevention, versus response and recovery.”
Protecting all of those assets is not feasible, as it would cost far too much, but not every substation is a critical asset that needs high levels of security, Robb said.
Even most incidents at substations would not qualify as attacks, with “criminal mischief” — in which people steal copper or vandalize substations — being much more common than occurrences like the attacks in North Carolina and Washington state and the foiled plot in Baltimore.
“But over the last six to nine months, we’ve seen more and more attacks, which would exceed the threshold of criminal mischief and really rise to the level of sabotage,” said Robb.
The increased concern over the rise in attacks is appropriate, but Robb said that only 5% of incidents at substations actually impact the grid, either by causing some customers to lose power, or by putting the system into a contingency operation mode.
CIP-014 (Physical security) was issued after the Metcalf Substation attack in Silicon Valley a decade ago. Its purpose is to ensure that physical attacks on substations did not lead to major, cascading outages on the grid, and so it focuses on substations with more power flows, at 345 kV and above, said Robb.
“While many substations may not need to be technically CIP-014-compliant, their owners may very well build in protections because it’s the right thing to do,” he added. “The utility sector generally leans in very, very hard on security matters, whether physical or cyber, to protect their assets and their ability to serve their customers.”
One idea for updating CIP-014 might be to focus on the possibility of coordinated attacks on multiple substations, said Robb. It could also shift from focusing on preventing cascading outages to preventing any outages at all, he added.
DOE Office of Cybersecurity Energy Security and Emergency Response Director Puesh Kumar and NERC CEO Jim Robb address the joint task force on Wednesday. | Federal State Task Force on Tran
Puesh Kumar, director of the U.S. Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, told the task force that the law enforcement community is very focused on the issue, as he is regularly meeting with the FBI and the Department of Justice.
“When we think of the law enforcement angle, that again doesn’t need to just be at the FBI level,” Kumar said. “We need to make sure that we have local law enforcement; we have state law enforcement also engaged in this conversation and really recognizing and appreciating the criticality of the electricity infrastructure across the country.”
Broad Solutions Save Money
With tens of thousands of physical sites requiring protection around the country, along with the need to protect the grid against cyber-attacks and extreme weather, it is important to focus on solutions that cut the risk across the board, Kumar said.
“How are we investing in tools and technologies that can also help us buy down the risk?” Kumar said. “It’s not just the standard that buys down risk; there’s a lot of other ways and tools and technology as part of the puzzle that we have to be thinking about.”
The biggest threat from a single-asset perspective is electric power transformers, which are just part of a substation’s equipment and thus could benefit from increased protections compared to other assets, PPL Electric Utilities Chief Information and Digital Officer Matthew Green told a panel at the NARUC summit earlier in the day. The risk around transformers can also be mitigated by ensuring the industry has enough backup equipment to replace anything that is damaged.
While physical attacks are a concern and a priority for PPL that is being addressed by prudently investing to protect the riskiest assets, it is not Green’s main worry.
“I’m actually more concerned around cybersecurity attacks,” Green said. “And, actually, in 2022 the single biggest contributor to outages for customers in United States continues to be weather-related outages. So that is also still a top concern.”
Investments to prevent outages from those causes need to be made prudently, after an accurate assessment of the relevant risks, he added.
The U.S. grid is decentralized, which means attacks on individual assets are unlikely to really have a major impact reliability across the board, said Kansas Corporation Commissioner Andrew French. But coordinated attacks are an increasing concern, so French asked Robb what the best strategy to address those would be.
One way of complying with CIP-014 is to remove any kind of critical substations from a utility’s network, which can happen in the process of normal grid planning or in coming back after a storm.
“I would love to see that number continue to decline, as we can build more and more redundancy into the system and less dependence on a subset of the assets around the grid,” Robb said.
Beyond that, coming up with a strategy to deal with the risk of coordinated attacks is tricky because it is not financially feasible to harden every grid asset out there. Having backup equipment available to minimize any downtime would help.
“One of the issues that’s vexing the industry right now, with all the supply chain challenges that we have, is that a lot of this equipment isn’t standardized,” Robb said. “So, I think that’s an opportunity as we as we move forward.”
Changes Needed for CIP-014?
Michigan Public Service Commission Chair Dan Scripps said it makes sense that CIP-014 is site-specific, but he asked whether it would also be prudent to have some kind of minimum level of protection spelled out in the standard.
The standard is fairly new, Robb said, so the industry has less experience from which it can draw best practices, but minimum standards are one of the updates that should be considered.
“There’s nothing that would prevent a state from imposing its own security requirements on any of these assets,” Robb said. “So, if to the extent that any of you feel that the NERC standards don’t go far enough to protect the systems under your jurisdiction from issues that you’re concerned about, you can always go further.”
Physical is usually an afterthought when it comes to planning the grid, but acting FERC Chairman Willie Phillips argued it would make sense to change that.
“If we consider it on the front end, I think we do have an opportunity to do something about what can be a very costly process,” Phillips said.
PJM has a process in which it works to minimize the number of critical infrastructure sites on its grid through planning, Phillips said, and that could work well elsewhere, as long as information on sensitive sites is handled correctly.
Connecticut Public Utilities Regulatory Authority Chair Marissa Gillett said that it might make sense to deal with physical security issues in the transmission planning process, but she worried that it would give the industry another excuse to shut out the states from the process in ISO-NE.
“I just think we need to be cognizant of some of the challenges around them,” Gillett said. “Especially because of that tension … between wanting to have openness while needing to respect the concerns about disclosing too much about physical security threats.”
The Federal Highway Administration on Wednesday announced key details of its effort to create a national electric vehicle charging network, including minimum standards for federally funded projects and an implementation plan for domestic content requirements for chargers.
Also Wednesday, the White House announced that major players in the EV industry would undertake an extensive buildout of chargers, and that Tesla would make part of its U.S. Supercharger network open to all EV brands for the first time.
A nationwide charger network is critical to ease a key barrier to widespread public acceptance of EVs — range anxiety, the fear of running out of power mid-journey.
The U.S. Department of Transportation has begun a $5 billion effort to counter this concern and encourage EV adoption: NEVI, the National Electric Vehicle Infrastructure program. (See US Completes Review of State EV Charging Plans.)
The rules announced Wednesday include, but are not limited to, NEVI-funded chargers and represent a step toward standardization. They are designed to create a more uniform experience for the EV-driving public, with consistent plug types and charging speeds; common payment systems; and accessible information on location, pricing and availability. Requirements for 97% uptime reliability and future compatibility will be imposed.
This sets the stage for municipalities, states and tribes to apply for the first round of $2.5 billion in competitive funding for charging stations under the Build America, Buy America Act.
The Biden Administration is working to create a national network of 500,000 EV chargers to support a goal of at least 50% of new car sales being EVs by 2030. It says there are now more than 3 million EVs on the road and more than 130,000 public chargers.
The latter number will get a bump from companies including Tesla, General Motors, EVgo, Pilot, Hertz and BP, with the White House announcing Wednesday that they would expand their public charger networks by thousands of plugs over the next two years.
Tesla has built a proprietary network of chargers compatible only with its own vehicles, though Tesla drivers can use many non-Tesla chargers with an adapter.
Under the agreement announced Wednesday, the company will make at least 7,500 Supercharger and Destination Charger stations available to non-Tesla EVs by the end of 2024. At least 3,500 will be along highway corridors. Tesla will also more than double its network of Superchargers.
In addition to Tesla’s efforts:
Hertz and BP are building a national network of chargers at Hertz locations, some of which will be large-scale gigahubs. Hertz wants to make a quarter of its rental fleet electric by the end of 2024, and BP plans to invest $1 billion in U.S. EV charging by 2030.
Pilot, GM and EVgo are building a network of 2,000 350-kW fast chargers, the first 200 of which will be online later this year.
TravelCenters of America and Electrify America plan approximately 1,000 chargers at 200 locations.
Mercedes Benz, ChargePoint and MN8 Energy plan more than 400 charging hubs with more than 2,500 public DC fast charging ports across the U.S. and Canada.
GM and FLO plan to install up to 40,000 Level 2 chargers in communities by 2026 through GM’s Dealer community Charging Program.
Some of these plans had been announced previously.
Four years ago, transmission developer Michael Skelly was on the outside of the electric industry looking in.
Clean Line Energy Partners, the company he had founded to deliver renewable energy over HVDC transmission lines, had sold off its portfolio of projects and closed its doors. Having taken a senior adviser’s role at Lazard Asset Management, Skelly was invited to speak at the American Wind Energy Association’s WINDPOWER 2019 conference. He said that while Clean Line hadn’t been able to “win the World Cup of transmission,” he was hopeful that “the second mouse gets the cheese in the transmission world.” (See Out of the Game, Skelly Still High on Wind Energy.)
As CEO of Houston-based Grid United, Skelly now leads a company intent on uniting the nation’s grid by building long-distance, interregional transmission to ensure access to low-cost power “when and where it is needed” — in other words, pretty much what Clean Line was trying to do.
Skelly’s company made a big splash recently by announcing a collaboration with ALLETE to build the North Plains Connector, a $2.5 billion, “first-of-its-kind” project that would span across the Western and Eastern interconnections. The 385-mile HVDC line will run from SPP’s wind-rich North Dakota footprint to the Colstrip power plant in Montana, where two 500-kV lines run into the Pacific Northwest. (See Transmission Project Would Span Across Interconnection Divide.)
Skelly said a number of wind projects are being built around Colstrip. Along with the region’s hydropower assets, it will give North Plains a chance to move power in either direction.
“During times when there’s excess generation in Montana, either from wind or solar or the spring hydro runoff, it will move power to the east into the Midwest,” Skelly told RTO Insider. “At times when there’s high load and low wind during the night and there’s no storage, it will power the West.”
The project, he said, will effectively improve renewable resources’ effective load-carrying capability, a measure of their ability to produce energy when the grid is most likely to experience shortfalls. Skelly said his staff did a backcast on the project to see how it would have performed under extreme weather conditions.
“As it turns out [during the February 2021 winter storm], they were short power in the Upper Midwest, and the Pacific Northwest had a lot of power. And similarly, when there was a heat over Seattle and Portland [last summer], there was plenty of power available in the Midwest,” Skelly said. “Our transmission is a very good way to deal with those extreme events, particularly transmission that can connect things that are a thousand-plus miles apart, because you’ve got very different weather phenomena.”
Grid United is also involved with the Southline Transmission Project, a 280-mile, high-voltage circuit between Tucson, Ariz., and the El Paso Electric system. The project also includes a 120-mile upgrade of existing Western Area Power Administration transmission lines.
“The focus of these grid projects is the things that we all know need to happen to improve resiliency and adapt to the change of generation, but that sort of fall between the cracks of the planning processes,” Skelly said, explaining how Grid United’s strategy is different from Clean Line’s.
“So, the model may be a hybrid model where we own interests and projects, and utilities own interests, or maybe the utilities own the whole thing. It will depend a lot on the specific project,” he said. “From a development perspective, our approach to development is to start to do a lot of the groundwork and a lot of the right-of-way work before we get down to the regulatory processes.”
And then there’s Pecos West, a 280-mile, 525-kV DC line from a substation in the middle of West Texas to El Paso. The project, still on the drawing board, would link ERCOT with the Western Interconnection. Grid United’s application for a “partial” certificate of convenience and necessity is on the Texas Public Utility Commission’s agenda for its open meeting Thursday (53758).
In a filing with the PUC on Monday, Grid United said a preliminary order is not necessary, pointing to its pending motion to abate. It said the abatement will give it time to work with ERCOT in obtaining any required studies or evaluations and that it will likely amend the CCN application with additional data that commission staff have requested. Grid United also wants a ruling from FERC that the project won’t affect ERCOT’s non-jurisdictional status; former FERC Chairs Richard Glick and Pat Wood have both said recently that such links can be made between the Texas grid and the other two interconnections without changing that status.
PUC staff, for their part, filed a motion in December to dismiss, saying it needed more information from Grid United.
“The PUC wants you to file a bunch of alternatives before you do any right-of-way work. We were trying to do the right-of-way work upfront, and then the filings,” Skelly said. “We apply; they asked for more info; we go back. We’re in that process right now. So far, it feels like it’s going fine.”
The North Plains Connector project is further advanced. Grid United has been working with SPP staff since last year; a feasibility study’s scope was approved in September by the Transmission Working Group. Former SPP COO Carl Monroe sits on Grid United’s four-person advisory board.
Skelly said that FERC’s efforts to improve the generator-interconnection process and focus on making transmission easier to site, build and fund, has raised public recognition of the grid’s importance.
“There’s a heightened awareness of the need for transmission,” Skelly said. “Even when you talk to a landowner and you tell them what you’re doing, they go, ‘Yeah, the grid; we got to fix that grid. We’ve got to make that grid better.’ You go to a cocktail party and you talk about the grid, people are like, ‘I heard there’s some issue with the grid. What’s going on with that?’”
Another sign of transmission’s importance is what has happened to the projects Clean Line left behind.
The Western Spirit project, a 155-mile 345-kV line in New Mexico, was energized in 2021. Invenergy is still working on the Grain Belt Express, an 800-mile HVDC line capable of carrying 5 GW of energy that starts in Kansas, runs through Missouri and ends at the Illinois-Indiana border.
“It’s still alive,” Skelly said. “Well, more than alive. They’ve ordered equipment. … That’s huge. Ordering equipment is a big step. You don’t do that unless you’re going to build it.
“Those are our old projects, so we’re excited about that,” he added. “You go through all that and, ‘Wow! Yeah, things have changed since 2019.’”
The NYISO Business Issues Committee on Wednesday voted to recommend that the Management Committee approve proposed tariff revisions to its participation model for distributed energy resource aggregations after the ISO committed to revisiting its unpopular 10-kW minimum for individual resource participation.
Stakeholders continued to express concern about the proposal, particularly the 10-kW rule, but were assuaged when NYISO promised it would re-evaluate “the ability of small facilities to provide wholesale market services as part of an aggregation” and look to “propose a set of market rules for small facilities that enhance grid reliability and resilience, reduce consumer costs, and lower barriers to entry for small DER.”
The 10-kW rule is perhaps the most controversial among a slate of revisions intended to integrate DER aggregations into NYISO’s markets. Although its model was approved in 2020, staff identified more changes they deemed necessary as they worked on implementing it. The ISO has said the rule is necessary while it gets used to integrating aggregations, as staff could be overwhelmed by so many smaller resources. (See NYISO 10-kW Min for DER Aggregation Participation Riles Stakeholders.)
Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, said he understood ISO concerns about being potentially overburdened by thousands of small-scale DERs, but he still would have preferred that “some level of flexibility was built into the tariff” to allow future changes without having to go through a “multi-month process” that is required to make revisions.
Final import rights results for 2023-24 capability year | NYISO
Rana Mukerji, NYISO senior vice president, responded that the ISO’s “intention is to work with [stakeholders] to find rules where we can accommodate all resources.” NYISO is “far ahead of peer ISOs and RTOs on comprehensive DER implementation,” leaving plenty of time to resolve these issues, he said.
Breidenbaugh also mentioned that the two planned stakeholder outreach sessions focused on DER may not be enough to address these issues.
Michael DeSocio, NYISO director of market design, responded that those meetings “are meant to kick us off and figure out how to organize future discussions.” Mukerji followed up with saying that the ISO has “administrative burdens that we need to overcome to integrate an aggregation with very small resources,” so it is critical that “stakeholders actively participate to help [NYISO] figure out” how to best resolve DER implementation questions.
NYISO will seek MC approval of the proposal Feb. 22. If the proposal is approved by FERC, NYISO will accept customer registrations for aggregators in mid-April, and start open enrollment of DER and aggregations in early summer, when the revisions are expected to become effective. It anticipates DERs being dispatched approximately 90 days after they have applied or whenever the ISO completes mandatory workflow reviews.
The ISO also told stakeholders they could attend two training sessions: one dedicated to DER onboarding and market participation, and one on operations that includes an overview of the participation model and operation of the Grid Operations Communication Portal.
Republican and Democratic legislators reacted warily to New York Gov. Kathy Hochul’s climate and energy proposals during a marathon budget hearing Tuesday.
Hochul administration officials defended her agenda against Republicans who think it is too aggressive and Democrats who think it is not aggressive enough.
The 2023/24 budget Hochul proposed includes policy changes and spending decisions that would bolster efforts to slash greenhouse gas emissions and transition to clean energy. The first checkmark — 70% renewable energy by 2030 — is only seven years away.
a “cap-and-invest” program to cut greenhouse gas emissions;
authorization for the New York Power Authority (NYPA) to begin developing its own renewable projects; and
a prohibition on new gas-burning appliances and heating equipment.
Both houses of the state Legislature are held by a Democratic supermajority; Hochul, also a Democrat, has many priorities in common with them but diverges on some of the details of achieving those priorities, sometimes significantly.
Like her predecessors’ executive budgets, her record $227 billion proposal is a starting point for closed-door negotiations, an aspirational wish list that will not emerge intact.
Cap-and-invest
The cap-and-invest proposal was a frequent topic. Some legislators expressed reservations that Hochul’s proposal is short on details on how the program would be designed, how the resulting money would be spent, and how certain large emitters of greenhouse gases would be chosen for exemption from the requirements.
Sen. Liz Krueger, the Manhattan Democrat wielding the gavel during the hearing, pressed Basil Seggos, commissioner of the Department of Environmental Conservation, on how much control the Legislature would have.
Not much, suggested Seggos, who said DEC already has sweeping authority to create such a program.
Krueger wondered if Hochul’s plan is weaker than what was recommended in the scoping plan recently completed for the state’s landmark Climate Leadership and Community Protection Act (CLCPA).
“Look,” she said, “I support this effort, but I’m a little confused about what we’re signing off, particularly in perpetuity; that generally makes me nervous as a legislator.”
Seggos said the state is consulting with stakeholders on what the regulations and structure should be, and it would be premature for him to discuss it. “We will be coming back to the public at a very aggressive rate over the coming five months before we even get into the regulatory phase,” he said.
The deadline for passage of the budget is only six weeks away.
Sen. Michelle Hinchey, an upstate Democrat, alluded to a recurring issue in New York government: Who controls the purse strings? Hochul’s cap-and-invest proposal is short on details, she said.
“It’s hard from our place of responsibility to greenlight an entire program without really understanding — even if we all kind of believe kind of deeply in the foundational points of it — where that’s going to go because historically we have lost lots of money that way. So we want to make sure we’re tracking it and it’s actually going to the places it needs to.”
NYPA Boost
Democratizing the energy sector and expanding public ownership is a goal of numerous advocacy groups, many of which have thrown their support behind the proposed Build Public Renewables Act, which is similar to Hochul’s proposal for NYPA.
But they do not like the way Hochul is proposing to do it, and have dubbed it “BPRA Lite.”
Her budget would not require NYPA to undertake development — only authorize it to do so — and she would give NYPA considerable discretion on how to go about development. Union-friendly provisions of the BPRA also are missing from Hochul’s proposal.
Assemblyperson Zohran Kwame Mamdani, a New York City Democrat, pressed acting NYPA CEO Justin Driscoll on the missing labor provisions. “Why has that language been removed and how do these omissions better position the state to unionize and expand the workforce needed to meet the goals of the CLCPA?” Mamdani asked.
Driscoll replied that NYPA already requires prevailing wages on its projects and is open to project labor agreements. He said a $25 million training fund would be created for new workers.
“I don’t see what’s missing,” Driscoll said.
“Did NYPA or the governor speak to labor before drafting this version of the Build Public Renewables Act?” Mamdani asked.
Driscoll said he could not speak for the governor.
“But for NYPA?”
“I did not personally. I can’t speak for my staff.”
NYPA acknowledged the “great challenge” of building renewables but is committed to doing it as economically as possible, Driscoll said.
NYPA needs to have case-by-case discretion on developing renewable energy projects, Driscoll said, which is why Hochul proposes to authorize NYPA to take such steps, not require it to.
NYPA could undertake small renewable projects on its own but is more likely to partner with other entities on larger projects because of its finite resources, Driscoll said.
Fear Factor
Hochul’s bill calls for a ban on installation of fossil fuel building systems in newly constructed residential buildings up to three stories tall starting Dec. 31, 2025, and in taller buildings starting Dec. 31, 2028. Retrofits in existing buildings up to three stories would be banned starting Jan. 1, 2030, and in taller buildings starting Jan. 1, 2035.There’s no specific ban on gas stoves proposed, but a ban on installing gas systems would at some point begin to limit use of gas cooking equipment.
Sen. Mario Mattera, a Republican representing some of Long Island’s suburbs, said constituents are anxious over being told they will need to replace their familiar fossil-burning fixtures with technologies whose costs, reliability and even availability are still unknown.
“People are frightened right now,” he told Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA).
A similar question had been asked of her earlier, and Harris again acknowledged the challenges facing the state, not least of which is building out electric vehicle charging infrastructure in New York City.
“You’re still not answering the question,” Mattera said. “Is this [reaching the state’s 2030 goals] feasible?”
“Certainly when we look … at the goals in the climate law for 2030, we do see them as feasible,” Harris replied. However, she acknowledged his point about communicating not just the goals for CLCPA but the steps that will be taken to reach them.
“We are not taking away gas stoves, as one example of perhaps misinformation we need to correct,” she said. “Also, we are going about this in a measured and deliberate way that does not create cliffs or specific reasons for alarm. This is a very rational, thought-out plan.”
Long Day of Q&A
The legislators had as little as three minutes each to question the witnesses, and some prefaced their questions with their own thoughts and opinions. So even though the hearing lasted more than 13 hours, witnesses often had time only to dash off half-answers or promise to follow up.
But the Q&A did yield some nuggets of information, including:
New York’s existing nuclear power plants are central to achieving the state’s goals, and the advanced nuclear technology now in development could also provide cost-effective benefits, Harris said.
Seggos said DEC will soon request proposals for a consultant to assess the cryptocurrency mining industry, which is under a two-year moratorium on building more of its power-intensive server farms in New York.
Only about 20% of the 11,000 communal EV charging station plugs in New York are accessible to the general public, Harris said.
Rory Christian, chair of the Public Service Commission, acknowledged complaints about the inability to connect new generation to the power grid but said the PSC is aggressively working on the issue and is on track to have generation and transmission infrastructure in place to accommodate all the electrification planned by 2030.
Rory Christian, chairman of the New York State Public Service Commission (left), and Houtan Moaveni, executive director of the New York state Office of Renewable Energy Siting, speak Tuesday at a joint legislative hearing on environmental conservation spending in the 2023-2024 budget proposed by New York Gov. Kathy Hochul. | New York State Legislature
The PSC’s mission and goal is preserving reliability of the power system through the clean-energy transition, Christian said, and if the transition plans are delayed or derailed, the plans will be reworked because reliability will remain paramount.
Hinchey, who chairs the Senate Agriculture Committee and represents a wide swath of farming communities, said there are too few braking mechanisms on development of productive farmland for solar arrays.
“We can’t replace a climate crisis with a food crisis,” she said.
Houtan Moaveni, executive director of the Office of Renewable Energy Siting (ORES), said the state will not meet its CLCPA goals without such integration of uses. He said ORES is looking at the marriage of the two through agrivoltaics but does not want to be prescriptive.
Hinchey thought it would make sense to hold off solar siting on farmland until agrivoltaic technology is mature and available because once farmland is gone, it is hard to get back.
New Jersey Gov. Phil Murphy on Wednesday outlined a sweeping set of new clean energy initiatives designed to accelerate the state’s goal of reaching net zero, including eliminating power sector emissions and ending the sale of gas-powered cars and light-duty trucks by 2035.
Speaking at Rutgers University in New Brunswick, Murphy set targets to require all electricity sold in the state be “derived from clean sources” by 2035 — 15 years ahead of the current goal — and install electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030. Murphy enshrined both measures in executive orders.
The governor also said he would step up the effort to cut transportation emissions by allocating $70 million in funds from Regional Greenhouse Gas Initiative auctions to reduce the “consumer upfront costs” for medium- and heavy-duty electric trucks.
Murphy added that he would direct the New Jersey Department of Environmental Protection (DEP) to begin the process of securing stakeholder input to implement a version of California’s Advanced Clean Cars II rules in New Jersey. The rules would require all new passenger vehicles sold in the state to be zero-emission vehicles by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
“These bold targets and carefully crafted initiatives signal our unequivocal commitment to swift and concrete climate action today,” Murphy said.” These comprehensive initiatives will better protect and prepare every New Jersey community, including those on the front lines of climate change who have previously been left out and left behind.”
The initiatives also included making 10% of all low-to-moderate income properties electrification-ready by 2030, part of an effort to reduce emissions from the state’s second largest source of greenhouse gases — homes and businesses.
Anticipating the opposition he might face, Murphy said, “No one is going to be forced to do anything,” and added that “No one is coming for anyone’s gas stove.”
“What today is about,” he said, is “giving consumers more choices and more chances to join us in creating a cleaner, more sustainable and more affordable energy future.”
He said his strategy of promoting a shift to electric heating and cooling systems would put “money right back into the pockets of consumers who choose to make the switch.”
Master Plan Concerns
The speech came just under a month after Murphy, who is thought to be preparing to run for president, announced plans to spend more than a year updating the 2019 Energy Master Plan that has underpinned much of the governor’s clean energy efforts, releasing the update in 2024.
In an apparently unrelated move, Sen. Bob Smith (D), who heads the Senate Energy and Environment Committee and shapes much of the state’s clean energy legislation, introduced a bill in January that would establish a sweeping new clean electricity certificate program to cover all energy sources. (See NJ Gov., Lawmakers Move Toward Updated Clean Energy Goals.)
New Jersey has sought to position itself as a clean energy leader, especially with its aggressive plan to build 11 GW of offshore wind power — of which three projects totaling more than 3.75 GW have been approved — and develop a special-purpose offshore wind port to handle the turbine supply chain.
But as the clean energy plans have grown, so have concerns about the cost and impact, with opponents urging the state to focus more on alternative low-emission fuels under development.
After vigorous business and union opposition, the DEP in December backed away from implementing a controversial rule that would have prevented the agency from issuing permits for new fossil fuel-fired boilers in certain situations. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.)
And critics of the master plan’s emphasis on shifting to making electricity the state’s main energy source have backed a bill, S2671, that would prohibit any state agency from mandating the use of electric building energy systems until the release of a government report on the costs and benefits of electric heating.
Eric DeGesero, executive vice president of the Fuel Merchants Association of New Jersey, which supports the bill, said he was “gratified to hear Governor Murphy announce that no homeowner or business will be mandated to switch their appliances to electric heat.” DeGesero said 85 % of New Jerseyans heat with natural gas, fuel oil or propane.
“The Murphy Administration and the legislature need to include all energy options on the table, not just electrification,” he said. “Focus should now shift to the most cost-effective way to decarbonize the incumbent fuels to those of the future.”
Preparing for an Electric Future
Murphy acknowledged that his plan “begs the question, ‘What happens to our natural gas utilities as we reduce our reliance on fossil fuels?’”
In response, he issued another executive order Wednesday that directs the state’s Board of Public Utilities (BPU) to “engage with all stakeholders from across the energy industry, organized labor, the environmental spaces, and the Governor’s Clean Buildings Working Group, to take on the big question of the future of the natural gas utility.”
The order said the topics for scrutiny would include:
the “need to ensure reliable operation and long-term financial viability of natural gas public utilities” as their consumer base shrinks;
alternative programs and “investments that could provide natural gas utilities with new revenue streams and promote good-paying jobs;” and
the “elimination of subsidies that encourage unnecessary investment in natural gas infrastructure that is likely to result in stranded costs to customers.”
BPU President Joseph L. Fiordaliso called Murphy’s request for 100% clean energy by 2035 “an incredibly important and sensible policy initiative that solidifies New Jersey as a leader at the forefront of the battle to address the climate crisis.”
The proposal also drew support from two prominent environmental groups, the New Jersey League of Conservation Voters and the New Jersey Sierra Club.
Ed Potosnak, executive director of the state’s League of Conservation Voters, said the organization is “thrilled to see a roadmap to 100% clean electricity, meaningful commitments to electrify buildings, vans, trucks and buses, and updated coastal rules to protect families and businesses — all as we step up efforts to protect our communities from the impacts of climate change.”
WASHINGTON ― The Tennessee Valley Authority has set its sights on 80% carbon-free generation by 2035 and a net-zero system by 2050, with plans to develop a fleet of up to 20 small modular nuclear reactors to meet the utility’s need for increasing amounts of secure, decarbonized electricity, according to CEO Jeff Lyash.
“I have no interest in building one reactor,” Lyash said during a session on nuclear development at the National Association of Regulatory Utility Commissioners (NARUC) Winter Policy Summit on Sunday. “In order for us to be successful, TVA needs something on the order of 20 reactors over that period of time. So, if you can’t see your way to reaching nth-of-a-kind costs, supply chain, workforce, project execution for a portfolio of reactors, I don’t see the point in building one.”
Approved by the TVA board in February 2022, the federally owned utility aims to build its first SMR at its Clinch River location in Tennessee, which now has an early site permit from the Nuclear Regulatory Commission. Separate from a construction permit, this permission provides safety, environmental impact and emergency preparedness approvals for a site where one or more nuclear plants may be built.
TVA will still need a construction permit for the 300-MW GE Hitachi BWRX-300 SMR it is now considering for potential deployment at Clinch River. The utility’s goal is not only to show that the technology works, Lyash said, but that it can be deployed “in a way where you can demonstrate the ability to build enough reactors to materially affect the outcome we’re looking for, which is energy security, decarbonization in the face of electrification and economic growth.”
The rising profile of nuclear power as one of the critical technologies that will power the U.S. to a carbon-free grid was a major theme at the NARUC conference, with Sunday’s session followed on Monday by an on-stage interview with David Wright, a member of the Nuclear Regulatory Commission.
Introducing Wright, who is also a past president of NARUC, Commissioner Tricia Pridemore, chair of the Georgia Public Service Commission, announced the formation of a new Advanced Nuclear State Collaborative, which will bring together members of NARUC and the National Association of State Energy Officials. The Department of Energy is sponsoring the initiative, which will provide technical assistance and expertise for states deploying or considering new nuclear projects, Pridemore said.
The initiative is one answer to the growing interest in nuclear across the country. In at least 20 states, “public service commissions and state energy offices are engaged in feasibility studies for advanced nuclear reactor site selection, strategies to reduce regulatory and policy barriers to new nuclear, and other activities to pave the way for advanced reactors,” she said.
Wright also sees possibilities for the NRC to develop more active relationships with state commissions and policy makers. “There are things [utility commissions] are going to be involved in that need our expertise or maybe even just information,” he told Pridemore.
“There are things you’re going to want to do, and you’re going to want to know — ‘Can I do that?” he said. “Do we have to put certain regulations in place on the state level, or does the legislature have to do certain things?’”
But a bigger question looms for the U.S. nuclear industry and its supporters, including TVA and DOE, which is pouring billions into the development of advanced reactors: Can they adequately de-risk a technology known for massive cost overruns and project delays to build the trust of financial markets and the public at large ― and how fast can they do it?
The Value of Vogtle
The two units nearing completion at the Alvin W. Vogtle Electric Generating Plant near Waynesboro, Ga., are a case in point. Vogtle’s two existing reactors have been operating since the late 1980s, but the plant’s next-generation expansion has become the poster project for cost overruns and delays, with Georgia’s rate payers picking up the tab with higher electric bills to finance construction.
The first new nuclear generation built in the U.S. in 30 years, the project is now six years behind schedule, and its original cost estimate of $14 billion has ballooned to more than $30 billion. Vogtle has also received $12 billion in loan guarantees from the Department of Energy’s Loan Programs Office (LPO), made during both the Obama and Trump administrations.
The first new unit at Vogtle is now expected to come online in May or June, a delay from the previous target of the end of April, Georgia Power said Feb. 16. The second unit is scheduled to begin commercial operation between this November and March 2024. Georgia Power also wrote off $201 million in additional costs for the reactors, reflecting increased costs. Together, the two units will provide 1,250 MW of power.
With completion finally in sight, the industry narrative on the troubled project is focused on its upside and long-term benefits.
Joining Lyash for Sunday’s nuclear discussion, LPO Director Jigar Shah said that Vogtle shows that “America is deciding to do big things. …
“We had to train 13,000 men and women, who were all union, to build those projects, and we now have that trained workforce, and many of those folks paid off debt for their entire families,” Shah said. “I think the transformational nature of what Vogtle did is something that we should celebrate, celebrating the persistence, the spirit of nuclear to get that done.”
That persistence also paid off in Poland’s recent decision to choose the same Westinghouse AP1000 reactors soon to go online at Vogtle for its first nuclear project, Shah said.
Similarly, Lyash sees Vogtle as a first-of-its-kind project that has produced valuable lessons learned. “The key is to have the fortitude and the confidence to harvest those learnings and integrate them and to use [them] to benefit the nation,” he said.
“And those lessons are around project management and execution, risk management, what a supply chain looks like, what the workforce needs to look like,” he said. “Vogtle has helped build the end capabilities now that I’ll be taking advantage of if we move forward with the BWRX-300.”
Despite Vogtle’s problems, Lyash predicted that “a decade from now, you’re going to be very, very happy that you have those facilities. They’re going to be impacting the economy and the environment, and they have generated a design that is beginning to be deployed around the world.”
Shah said, even today, the LPO would provide the same loan guarantees to the project. A key point for such decisions is whether the office sees “a realistic prospect of repayment,” and he expects Vogtle will fully repay its loans.
‘A Fragile System’
The positive momentum for nuclear at NARUC notwithstanding, opinions nationwide about moving forward with new plants remains divided. In its most recent poll on the issue, Gallup found support for nuclear edging up to 51% versus 47% opposed, a slight shift from 2019, when the country was evenly split, 49% to 49%.
A Pew Research poll taken before Russia’s invasion of Ukraine last year found that 35% of those surveyed said the U.S. government should support nuclear; 25% said the government should not support it; while 37% were neutral on the issue.
Opinions also differ on the cost of maintaining the country’s existing 92 nuclear reactors, which provide about 20% of the nation’s power and 50% of its carbon-free electricity.
At the Sunday session, Commissioner John B. Howard of the New York Public Service Commission raised the issue of state subsidies for existing plants, such as New York’s zero-emission credits (ZECs) “that many believe are not affordable and sustainable.”
Nuclear power development has gotten too expensive, Howard said.
A recent NARUC report on the U.S. nuclear market lists New York, Illinois, Connecticut, New Jersey and Ohio as providing ZECs for their existing plants. The Infrastructure Investment and Jobs Act also provides $6 billion in funding for a Civil Nuclear Credit Program to help plants stay open.
But Lyash countered that nuclear plants are “highly competitive.”
According to the NARUC report, more than two-thirds of the clean power supply in 20 states comes from nuclear, and in Mississippi, nuclear accounts for 96% of the state’s carbon-free power.
Nuclear is 42% of TVA’s power supply, Lyash said, and he expects that percentage to hold steady even as the utility’s electricity demand increases with economic growth and electrification of buildings and transportation.
Nuclear plants are “high capital on the front end, but they have a tremendously long and beneficial life,” he said. “They also deliver all the attributes to a power system that you need — voltage, frequency, maneuverability.”
Echoing a familiar nuclear industry argument, Lyash said ZECs should not be seen as subsidies, but rather as paying nuclear plants “for the value that they already delivered because markets have a difficult time recognizing that.”
Shah framed the case for nuclear in terms of system reliability. “We have a fragile system, and that fragility has come from [independent power producer]-run natural gas plants,” he said. “For the last three years, we have seen a historic amount of failure out of those gas plants. … For many people, nuclear power represents a better form of baseload clean power to be able to provide that to people long term, [but] what they are afraid of is that we haven’t figured out how to build them on time, on budget.”
TVA’s Clinch River project could be the next step toward that goal, he said.
Lyash countered that the issue was not system fragility, per se, but the rising expectations of customers who are themselves increasingly dependent on electricity. “If you roll back 75 years, only about 2% of all the end-use energy in this country came from electricity; today it is 22%, and by 2050, it’s probably going to be 50%,” he said.
“The level of reliability on the U.S. electric system hasn’t generally degraded,” Lyash said. “The customer expectations have risen, and not just day-in, day-out reliability … but resiliency — how does it perform when it’s [confronted] with the thing you hoped would never happen or happens infrequently,” such as December’s Winter Storm Elliott.
“People’s expectations are entirely different. … Twenty years ago if your lights went out for 20 minutes, or flickered, you would not have cared,” he said. “Today you really care about this.”
‘No Shortcuts’
Lyash also sees SMRs, like the BWRX-300, as easier to integrate on the grid. Smaller reactors could be strategically sited to ease transmission congestion, and in the event of an emergency, taking 300 MW offline would be less disruptive to system reliability than bigger units, he said.
Lyash, Shah and Wright are expecting nuclear development in the coming years to be centered on or near closed coal-fired plants with existing transmission, circumventing the need for extensive new transmission construction.
Shah pointed to a recent DOE study that identified 157 closed coal plants and an additional 237 coal plants still in operation as potential sites for coal-to-nuclear transition. The study also found 80% of those sites well suited for the development of advanced reactors of less than 1 GW.
For example, TerraPower’s 345-MW Natrium reactor, one of two projects being developed under DOE’s Advanced Reactor Demonstration Program, is being planned for Kemmerer, Wyo., where a PacifiCorp coal-fired plant is scheduled for retirement in 2025. The DOE program has $2.5 billion in funding from the Infrastructure Investment and Jobs Act and is supporting the development of two advanced reactors that are scheduled to be online by 2027.
The second reactor, X-energy’s Xe-100, is being planned for a site in Washington state near an existing nuclear plant.
Wright sees these demonstrations and other coal-to-nuclear projects as the “low-hanging fruit” of the next wave of nuclear development. Siting a nuclear project on or near a closed or existing coal or nuclear plant could streamline permitting because “they’ve already got an [environmental impact statement],” he said. “We don’t want to have to do an [analysis] if they’re going on a site that’s already been done. …
“There may be some tweaking to some regulations and rules we have to do in order to get ready, but we don’t want to be the reason that they delay [or] they don’t even get to market,” he said.
NRC is also staffing up in preparation for what it expects to be an increasing number of projects applying for approval, Wright said. “We’re onboarding 400 this year,” he said.
While planning for an aggressive nuclear buildout, Lyash said TVA wants to pursue a diversified portfolio of clean energy resources that balances energy security, affordability and decarbonization. “No one resource can satisfy” these goals, he said. “You have to think about this not as a choice between wind or solar or nuclear or hydro or storage. It’s the combination of all the right technologies in a portfolio that delivers energy security and [clean] energy to drive the economy.”
Shah agreed, saying all resources should be on the table. The enthusiasm for nuclear at NARUC is part of the growing interest in other technologies, such as enhanced geothermal and low-impact hydropower, he said. Going forward, he sees industry enthusiasm and support for “all of the tools that have reached the level of maturity so they can rise to the occasion” of decarbonizing the U.S. economy.
But Shah said the greatest challenge ahead for nuclear may be building trust. “I think the nuclear industry, for better or for worse, was dormant for the better part of 30 years, not really pursuing innovation for the better part of 30 years,” he said. Now the industry is developing SMRs and other innovative advanced reactors, but “they have to do a proper job. They have to learn all the lessons. They’ve got to make sure they measure 34 times and cut once.
“There’s no shortcut to building trust,” Shah said. “It’s about doing these things in a highly competent fashion, making sure there is transparency, that we’re fully admitting all the mistakes that were made in the past and learning from them.”
Physical attacks on electric infrastructure have been the upswing over the past year, with recent attacks in North Carolina and Washington state and a foiled plot in Baltimore bringing more attention to the issue, experts said at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit on Sunday.
“Over the last year, we’ve seen a marked increase in security incidents,” NERC Senior Vice President and Electricity Information Sharing & Analysis Center (E-ISAC) CEO Manny Cancel. “So the bad news is that there has been an increase — a fairly significant one compared to the baseline of the previous five years.”
While attacks are on the rise, only a small portion of physical attacks actually cause any damage to the broader power grid, Cancel said. But those that do can have major impacts, such as in North Carolina late last year. (See Duke: NC Outages from Attacks May Last Until Thursday.)
Physical attacks have been clustered close together geographically, sometimes with multiple assets in the same area targeted, and sometimes the same infrastructure has been hit more than once, said Cancel.
While a handful of suspects have been arrested, in most cases the industry is not aware of who is attacking its infrastructure, Cancel said. Some of the cases are clearly just petty theft with infrastructure being stripped of copper or other valuables.
FERC and NERC have set up mandatory Critical Infrastructure Protection (CIP) standards that deal with both cyber and physical attacks. Those standards helped to minimize the impact of the North Carolina attack in December, Cancel said, but NERC is also working on expanding those to better protect the grid.
Reliability standards today are focused on protecting against grid instability and preventing cascading outages, but going forward, Cancel said, it might make sense to update standards to minimize the loss of load from attacks and to better protect against coordinated efforts such as the foiled plot in Baltimore, where neo-Nazi extremists planned to attack multiple assets. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)
While physical attacks on the grid have made more headlines recently, the E-ISAC and NERC spend just as much time on cybersecurity, which can prove riskier to the grid.
“Certainly, cyber has the capability to do more at scale,” Cancel said. “And certainly when you factor in the capabilities of nation-state adversaries, those are very complex adversaries that have really strong potential … to carry out attacks.”
The recent spate of attacks has the industry on the verge of a paradigm shift, said Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security.
“If you remember, prior to 9/11, the airport security … was effective for the cost that we paid,” he said. “After 9/11, there was a paradigm shift. And so you know, we paid a lot more [for] a lot more security and a lot bigger hassle associated with that security, but it was worth worth the cost.”
Historically, the main security worry for the industry was a random person wandering into a facility and getting hurt, which could be taken care of with fences, McClelland said. But now the industry needs to step up its game by analyzing risks around the grid and coming up with a cost-effective plan to make it more effective.
CIP standards are foundational practices to ensure a minimum level of security, while McClelland’s group at FERC is focused on best practices.
“We’re looking for those advanced adversaries that specifically target our energy infrastructure,” McClelland said. “Using this two-pronged approach, FERC can move very quickly, even against the most advanced aggressor.”
The commission works closely with other governmental agencies to determine who is trying to attack the grid, which can help it come up with best practices for defense. FERC staff can then bring some of that information down the industry, even granting state commissioners one day of security clearance so they can be briefed on any relevant threats.
“We will read in, so to speak, those state commissioners, and in that session, we’ll do a classified briefing,” he added. “But as importantly, perhaps more importantly, we do a working session where we talk specifically about how these adversaries can be stopped.”
As threats emerge in between those briefings, FERC will also issue advisories so that any new major issues are known by those under threat.
“If there are utilities that are particularly targeted, or the networks and systems that they operate have shown some vulnerabilities and showing some attention from adversaries, we will contact those utilities and we will work specifically with them to help them understand the threats and then work with them to also assess how vulnerable they are to the threats,” McClelland said.
Another way of informing the industry is through a regular tabletop exercise called “Cyber Yankee” that FERC holds with the industry in which they simulate grid attacks based on real threats, McClelland said.
The SouthCoast Wind project could have significant impacts on marine mammals, fisheries and navigation off the Massachusetts coast, according to a draft environmental impact statement.
The U.S. Bureau of Ocean Energy Management on Monday announced the release of the draft EIS for SouthCoast Wind, formerly known as Mayflower Wind, about 20 miles south of the island of Nantucket.
The 127,388-acre lease area has a generation capacity of up to 2,400 MW. SouthCoast Wind Energy, a joint venture of Shell New Energies US (NYSE:SHEL) and Ocean Winds North America (EDP Renewables and ENGIE), announced its new name Feb. 1.
SouthCoast plans to establish grid connections in Massachusetts for the first 1,200 MW, though the company has indicated the terms it negotiated for sale of 400 MW of that electricity have become uneconomical. (See Financial Concerns Continue for Major Northeast OSW Projects.)
With its appendices, the BOEM report totals 1,927 pages. It examines the potential impacts of the project as proposed and of four modified versions, as well as the anticipated result of the status quo if the project were never constructed.
Most of the findings are presented as a range of possibilities, and most of the alternatives resulted in little change in the projections.
Air quality, for example, could see minor adverse impacts from the emissions associated with construction and minor beneficial impacts from less fossil fuel being burned to generate electricity, once the offshore wind turbines come online.
Habitat disturbance could have a negligible to moderate negative impact on marine life forms, but the new underwater hard surfaces could create new habitat, and therefore have a moderate beneficial impact.
Some birds would be killed by spinning turbine blades, others would see their shoreline habitats disturbed, and still others would gain increased foraging opportunities; together, the report rates these as both a minor negative and minor beneficial impact.
Underwater noise and increased risk of collisions with vessels would affect whales and other marine mammals to an unknown degree; the report rates the negative impact as anywhere from negligible to major.
The commercial fisheries would suffer a minor to major impact, depending on the type of fishery; most vessels could adapt their operations to adjust but others would experience significant and lasting disruptions. The cumulative fisheries impact of this and other wind energy projects proposed off the Northeast U.S. coast is rated as major.
The report says the commercial species most affected in the offshore project area is longfin squid. Atlantic surfclam and ocean quahog fisheries told BOEM their operations require a minimum distance of 2 nautical miles (3.7 kilometers) between turbines for safe operations. The report said problems could also arise if mobile species such as Atlantic herring, Atlantic mackerel, squid, tuna and groundfish, are attracted to the wind farm area.
SouthCoast plans up to 147 wind turbine generators standing up to 1,066 feet tall, spaced 1 nautical mile apart in a uniform north-south/east-west layout.
Although state officials have embraced offshore wind as a source of economic development, BOEM projects minor employment and economic impacts from the project, with negative impacts on fishing and recreational pursuits and positive impacts on job creation and tax revenue.
Little net impact is seen on environmental justice, except in the case of tribal nations, because of the potential major impacts on submerged ancient landforms.
Vessel traffic might be impacted by the wind farm, perhaps even to a moderate degree, because of revised navigation routes, port delays and degraded radio and radar signals. A moderate negative impact is foreseen on search and rescue operations, and a major impact is expected on scientific research and surveys.
BOEM, which will publish the draft report Friday in the Federal Register, will accept public comment through April 3. It has scheduled three virtual public information sessions in late March.
