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November 20, 2024

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NY Contracts More Than 2 GW in Solar and Storage Projects

New York Gov. Kathy Hochul on Thursday announced awards for 22 solar and energy storage projects totaling 2,078 MW, the state’s largest land-based renewable energy procurement to date.

The New York State Energy Research and Development Authority estimates the projects will drive over $2.7 billion in private investment and create over 3,000 short- and long-term jobs while helping achieve the state’s environmental goals.

The Climate Leadership and Community Protection Act requires the state to obtain 70% of its electricity from renewable sources by 2030 and to make the grid net-zero by 2040.

“These projects will allow us to not just meet but exceed our goal of obtaining 70% of our electricity from renewable resources and will further cement New York as a national leader in the fight against climate change,” Hochul said.

“Today’s announcement of 22 exciting new clean energy project awards demonstrates that New York state continues its strong commitment to clean our electric grid, and the renewable energy industry is seriously stepping up to develop and invest in New York. We look forward to the construction jobs and pollution-free power these projects will deliver,” Anne Reynolds, executive director of the Alliance for Clean Energy NY, said.

The 22 large-scale projects feature several solar facilities combined with co-located storage, including the 350-MW Ridge View Solar Energy Center in Niagara County with 20 MW of storage; the identically sized Columbia Solar Energy Center in Herkimer County; the 240-MW Rich Road Solar Energy Center and 20-MW storage facility in St. Lawrence County; and the 250-MW Fort Covington Solar Farm with 77 MW of co-located storage in Franklin County.

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MISO Annual Transmission Package Nears $4B

A draft version of MISO’s 2022 Annual Transmission Plan (MTEP 22) calls for $3.8 billion in spending for 364 of the footprint’s new transmission projects, a $500 million increase over a February draft. (See Initial MTEP22 Portfolio has $3.3B in Costs.)

During a series of subregional planning meetings last week, stakeholders learned MTEP 22’s $3.8 billion value is an increase over the $3 billion MTEP 21 portfolio, which had 335 projects.

MTEP 22 contains about $1.5 billion earmarked for projects addressing aging existing infrastructure, $1 billion for projects accommodating load growth, $580 million in necessary baseline reliability projects to meet NERC standards, another $530 million in projects to solve more garden variety reliability issues and nearly $250 million in projects to interconnect new generation.

MISO South has been assigned 30 projects, valued at $810 million. Six of the 10 most expensive projects are located in the region. The projects, submitted by Entergy’s Texas, Louisiana and Arkansas subsidiary to meet load growth, range in price from almost $96 million to $50 million.

The most expensive MTEP 22 project is Duke Energy’s $100 million addition of a West Lafayette, Ind., substation, also driven by growing load.

During a Central Subregional Planning meeting Wednesday, MISO’s senior manager of transmission expansion planning, Thompson Adu, said the RTO is currently “resource constrained” on MTEP planning work because it continues to simultaneously plan the long-range transmission portfolios. (See MISO Makes Business Case on Long-range Tx Plan.)

The grid operator will hold another series of subregional planning meetings in early September to lay out the final MTEP 22 report. MISO’s Board of Directors will consider the portfolio’s approval in December.

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FERC Partially Accepts NYISO BSM Compliance Filing

FERC on Thursday accepted NYISO’s proposal to implement its revised buyer-side market power mitigation (BSM) rules for the current class year, but it ordered an additional filing by Aug. 1 to establish a specific effective date (ER20-1718-003).

The commission approved NYISO’s revisions, which allow the ISO to evaluate projects being driven by New York state public policy first, in February and ordered a compliance filing proposing an effective date for the changes, but one that was no later than the next class year.

NYISO did so in March, proposing that the revisions take effect immediately following the completion of class year 2021 that same month. (See NYISO Files BSM Compliance, Extension Request.)

FERC said that was fine, but that the ISO still needs to specify a date and include conforming tariff revisions based on that date.

Commissioner James Danly dissented, calling the brief letter to NYISO “yet another unlawful order that should never have [been] issued.”

“There is no material, legitimate basis to justify NYISO’s discriminatory treatment prioritizing the evaluation of public policy resources before non-public policy resources, independent of any other consideration, including cost,” Danly said.

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Ohio Lawmakers Propose Bill to Ensure Public Represented on PUC

Two Ohio lawmakers this week introduced legislation to significantly alter the composition of the state’s five-member Public Utilities Commission by requiring the governor to appoint one member from a list of candidates chosen by the office of the Ohio Consumers’ Counsel (OCC).

Under H.B. 690, the OCC, rather than the PUCO Nominating Council, would have the responsibility to vet and submit the names of three consumer-oriented candidates to the governor for appointment.

The governor would not be permitted to reject all three, and any OCC-recommended appointment would be subject to approval by the state Senate.

The PUCO Nominating Council would continue to screen candidates for the other four seats on the commission for gubernatorial appointment.

The introduction of the legislation follows Republican Gov. Mike DeWine’s reappointment in February of a long-time utility lawyer to a second five-year term after the Nominating Council, chaired by a utility lobbyist, rejected candidates with a consumer background.

It also comes three years after DeWine appointed utility lobbyist Sam Randazzo, whose clients included FirstEnergy (NYSE:FE), to chair the PUC. Randazzo stepped down in November 2020, four days after the FBI raided his home after FirstEnergy revealed in a Securities and Exchange Commission filing that it had paid him $4 million before his appointment to close out a six-year consulting contract.

Rep. Laura Lanese (R), one of two primary sponsors of H.B. 690, said she introduced the legislation to make sure the public, “the first word in the name of the Public Utilities Commission,” gets represented.

“We have this office, the OCC, that has the expertise” to ensure public representation, she said.

Lanese noted that the OCC is already responsible for recommending a gubernatorial appointment to the Ohio Power Siting Board, which has authority over the development of power plants, including wind and solar, transmission lines and pipelines.

“We do it with the Ohio Power Siting Board, and there’s no reason for us not to do it with the PUC,” she said.

Co-sponsor Gayle Manning (R) could not be immediately reached for comment, but a number of Democrats immediately agreed to co-sponsor the bill.

Rep. Kent Smith, ranking Democrat on the House Public Utilities Committee, which is expected to hold initial hearings on the legislation, is listed as one of the co-sponsors.

“I think the voice of consumers needs to be amplified on the PUC,” Smith said. “And this would be a relatively simple way to ensure that a consumer voice would be there.”

Rep. Casey Weinstein, a Democrat who clashed with Randazzo when he was appointed to the PUCO, said he quickly moved to be a co-sponsor.

“I just want to see more consumer-focused representation on the PUC, and I think this is a creative way to get there. I have not liked the governor’s picks. I think it’s all industry-friendly folks. I completely disagree with the preponderance of the decisions that they’ve made. I think they seem to exist to protect the status quo. And I think that should be challenged,” he said.

A third Democrat, Rep. Dan Troy of suburban Cleveland, said he immediately decided to co-sponsor the bill when he saw it. “I’ll be co-sponsoring this because it’s one more seat at the table that has the ratepayers’ interests in mind,” he said.

The spokesperson for the OCC issued a statement in support of the legislation.

“Years ago the legislature required that the Ohio Power Siting Board would have a member, to be nominated by the Consumers’ Counsel and appointed by the governor, as the public’s representative on the board. That was a good idea for Ohioans,” Merrilee Embs wrote in an email responding to a request for comment.

“A similarly good idea is in House Bill 690 for reform of the PUCO. That’s especially important given the PUCO is out of balance with two of five commissioners having formerly worked for the utility industry,” Embs wrote. “Just recently the PUCO even had three of five commissioners who had worked for utilities — until a FirstEnergy scandal led the former PUCO chair to resign. …

“In the interest of justice for millions of utility consumers, we urge the legislature to enact House Bill 690.”

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Interior to Cut Rent for Clean Energy Projects on Public Land

Renewable energy developers looking to build projects on public land may soon see the rent and fees they have to pay drop by more than half, Interior Secretary Deb Haaland announced Tuesday at a clean energy roundtable in Las Vegas.

The dramatic drop in the per-acre rent and per-megawatt fees developers pay is part of a drive by Interior and its Bureau of Land Management to help the Biden administration reach its 2025 goal of putting 25,000 MW of renewable energy projects on public lands, primarily in the West. Haaland also announced that the department will be setting up and staffing special units called Renewable Energy Coordination Offices (RECOs) “to prioritize robust environmental compliance coordination for renewable energy proposals.”

The RECOs will be located in BLM offices across the West, with one each in Arizona, California, Nevada and Utah, according to a DOI announcement.

In a statement included in the announcement, Haaland underlined the “important role” clean energy projects on public land will play in reducing U.S. greenhouse gas emissions and the department’s commitment to “coordination with local, state and elected officials, tribes, and conservation and industry groups.”

BLM Director Tracy Stone-Manning hailed the announcements as “bold steps” that will allow the agency “to attract renewable energy investments on public lands in a way that is environmentally sound.”

While Tuesday’s announcement was light on specifics — such as when the lower rates and RECOs will be rolled out — more detail can be gleaned from a progress report on renewable development on public lands that DOI and BLM submitted to Congress in March.

Authorized to reduce per-acre rental rates for clean energy projects in the Energy Act of 2020, the department implemented initial reductions in California’s Riverside, San Bernardino and San Diego counties in 2021 because of “significant increases in the fair market value for acreage rents” for solar and wind projects in those areas, the report says.

The reduced rates for states, recently published by BLM, range from $8.09/acre in New Mexico to $48.93/acre in Oregon. The reduced rate for all of California is $75.13/acre.

‘Vast Contiguous Areas’

Siting renewable energy on public land remains a potential flash point at the local level. For example, the recently approved Oberon solar project in Riverside County was opposed by some environmental groups, which see it as a threat to sensitive desert ecosystems and animals, such as the desert tortoise and fringe-toed lizard, as reported in The Desert Sun.

But with Biden’s ambitious climate goals and the need to rapidly ramp up solar and wind, “vast contiguous areas available for onshore renewable energy are sparse,” the DOI-BLM report argues. “Therefore, public lands … have a unique role to play” in renewable development.

According to the report, in fiscal year 2021, BLM helped develop 2,890 MW of solar, wind and geothermal energy on public land, a 35% increase over 2020.

Going into 2022, the agency had a pipeline of 54 solar, wind and geothermal projects totaling 33,000 MW that it is prioritizing for permitting by 2025, the report says. BLM is targeting approvals for 3,595 MW of solar in 2022, rising to 13,524 MW in 2024.

The pipeline also includes six interconnection transmission lines — or “gen-ties” — connecting renewable projects to the grid, with a total capacity of 1,732 MW. Four major transmission lines are also on the agency’s priority list: Greenlink West and North, both in Nevada; SunZia, in Arizona and New Mexico; and Transcanyon Cross-Tie, connecting Nevada and Utah.

Processing all those projects and staffing the RECOs will require at least 56 new hires, according to the report, and anticipated projects in states such as Idaho, Montana and the Dakotas could result in an additional RECO with a staff of 10.

Permitting has long been a pain point for renewable energy and transmission development, but whether the DOI initiatives will be enough to move projects forward on expedited timelines remains uncertain. While interconnection queues across the country sit with backlogs of hundreds of megawatts of projects, supply chain delays and the Commerce Department solar tariff investigation have put major dampers on solar development.

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ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets

Inflation and investments in cybersecurity are likely to continue driving budget increases across the ERO Enterprise for the next several years, staff at NERC’s regional entities warned in a webinar hosted by the ERO’s Finance and Audit Committee on Wednesday.

The webinar was meant to provide more context for NERC and the REs’ draft 2023 business plan and budgets. NERC posted the drafts last Wednesday; the organization is seeking comment on the documents through June 24 and plans to submit the final budgets to its Board of Trustees for approval at its next open meeting in August. (See NERC Plans Big Budget Hike for 2023.)

The draft budgets indicate that the ERO Enterprise’s efforts to reduce the costs of the economic hardships of the COVID-19 pandemic are coming to an end, as NERC predicted when it released the preliminary 2022 budget last year. (See NERC: Post-COVID Budget Rises Likely.) NERC’s planned 13.5% budget increase ($12 million) is its biggest by percentage since 2015, when the creation of the Cybersecurity Risk Information Sharing Program spurred an 18.3% growth. It is also significantly higher than the 7.1% increase from 2021 to 2022.

The REs are all planning budget hikes of their own, ranging from the Texas Reliability Entity’s budget of $17.7 million, up 3.2% from this year, to the Midwest Reliability Organization’s $23 million, up 15% from 2022. NERC also expects to raise its assessment next year, as does every RE except for WECC, which is planning a 17.2% reduction.

Presenters at Wednesday’s webinar included finance heads from every RE, discussing the drivers of their expected budget increases. A common theme was the need for REs to resume investing in needed improvements that many had deferred in recent years to avoid raising assessments and burdening utilities that were themselves struggling with adapting to the pandemic.

Lam Chung (NERC) FI.jpgLam Chung, MRO | NERC

“We are sort of working our way back out of that hole that we’ve created for ourselves … in light of the financial and economic situations of the last several years,” said Lam Chung, vice president and engineer for strategy, innovation and finance at MRO.

For many REs, the most significant investment needed is in cyber and physical security. ReliabilityFirst, for example, plans to increase its budget by 6.7%; 48% of this increase consists of security initiatives and salaries for new security personnel.

Texas RE also plans to add an additional full-time-equivalent position in its information technology department, while WECC expects a 12.2% increase in its operating expenses because of costs associated with computer improvements and enterprise security tools. SERC Reliability CFO George Krogstie said his organization is “completing … a multiyear shift from third-party to in-house IT expertise,” which has resulted in “greater autonomy to manage our network.”

Presenters observed that the current rates of inflation — the U.S. Consumer Price Index was near a 40-year high in April, according to The Guardian — also complicates the budget process, with many complaining that even if they continue to hold most meetings virtually, they will likely still have to raise their meeting and travel budgets to keep pace with rising costs. The wave of inflation is also boosting costs of insurance and other services while putting pressure on REs to raise their salary offerings to stay competitive, especially for urgently-needed hires in cybersecurity.

“We have adjusted our merit increase for inflation, [which is] typically 3%; we’ve moved that to 4%. And we also have inflation increases in meetings and travel,” said Carol Baskey, treasurer at ReliabilityFirst. “We [also] have a newer, less experienced staff than in prior years, so there’s more training that we’re going to be taking on as well.”

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Granholm Discusses Net-zero Tech at ARPA-E Energy Innovation Summit

DENVER — Leaders in energy innovation from across the U.S. traveled to Denver last week to participate in ARPA-E’s 2022 Energy Innovation Summit.

The three-day conference ended with a fireside chat led by U.S. Secretary of Energy Jennifer Granholm.

Granholm started by expressing her excitement to be back in person.

“Since the last time we met virtually, so much has gone on in the world, even yesterday, so much horrible stuff,” Granholm said, referring to the school shooting in Uvalde, Texas.

Jennifer Granholm 2022-05-25 (RTO Insider LLC) FI.jpgU.S. Energy Secretary Jennifer Granholm | © RTO Insider LLC

“[And] the war in Ukraine as well,” she continued. “The impacts on the global energy markets and the fact that gas prices are through the roof and people are really hurting. It just tells you that we have got to move.”

Granholm expressed frustration with the current legislature’s inability to “get the full array of our climate policy through,” but she said she remains optimistic.

“Technology is going to move forward regardless of what’s happening on the policy side, and this is how we are going to ultimately fix the biggest problems that are facing us,” she said.

Beth Zotter, CEO and co-founder of UMARO Foods, and Natron Energy CEO Colin Wessells joined Granholm for a conversation about the technologies their companies are working on to aid the transition to net zero.

Zotter’s company started out by producing algal biofuels out of seaweed to use in the transportation sector.

“UMARO Foods is really built on the vision that the ocean is the most scalable and efficient bioreactor for producing biomass,” Zotter said. She added that the company’s goal is to create the technologies that can unlock the ocean’s potential for producing clean energy.

Her company has moved into the food industry, using seaweed biproducts to produce plant-based foods to complement its existing biofuel production. UMARO plans to roll out plant-based bacon to restaurants in the coming months.

“Right now, algal biofuels need a high-value co-product to basically make the economics for large-scale biorefineries work out,” Zotter said. And with a growing demand for plant-based meat alternatives, it’s a new market opportunity, she added.

On the battery storage front, Wessells said, “Natron Energy is developing sodium-ion batteries to solve electricity reliability problems,” while avoiding widespread industry supply chain issues.

ARPA-E panel 2022-05-25 (ARPA-E) Content.jpgU.S. Energy Secretary Jennifer Granholm (right) participates in a fireside chat with Natron Energy CEO Colin Wessells (left) and UMARO Foods CEO Beth Zotter. | ARPA-E

“We’re removing the supply chain constraints,” he said. “We don’t have the lithium; we don’t have the cobalt; we don’t have the nickel; we don’t have the copper. We can onshore all these materials. We just use iron; we just use manganese.”

Natron is planning a large battery storage project in Holland, Mich., with its new sodium-ion technology. It plans to run about 600 MW of battery production per year of utility-scale grid storage for “data centers, telecom [and] short-duration grid storage. … This will be phase one of a longer-term growth plan,” he said.

With LG Energy Solutions’ investment in battery manufacturing for electric vehicles in March and the various auto manufacturers in the area, Wessells said Holland is poised to become a battery hub in the Upper Midwest.

Wessells said Natron’s goal is “to avert a doomsday scenario for grid storage, where if we don’t have the lithium minerals, we don’t have the grid storage we need.” Being independent of the mineral supply chain may allow Natron to fill the battery storage gap that will get the U.S. to net zero, he said.

Both companies were able to launch with help from funds awarded through ARPA-E grants. Granholm stressed the importance of government working with industry to fund technologies to avert climate change and aid the energy transition.

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Counterflow: Transmission and Technology

tesla powerwallSteve Huntoon | Steve Huntoon

Around the middle of the massive FERC Notice of Proposed Rulemaking on transmission planning, etcetera, we come across a discussion of new technologies.

The NOPR says transmission planning will be improved with the use of dynamic line ratings and other “grid enhancing technologies” (GETs).[1]

Dynamic Line Ratings

It’s hard to see how this can be so. Dynamic line ratings are very important for reducing congestion, as I discussed back in 2019.[2] But they can’t relieve reliability violations — arising from future system conditions or from interconnecting new generation.

Planning is based on worst-case system conditions. Dynamic line ratings can be used to increase dispatch of lower cost resources when temperature and other ambient conditions are better than worst case. But they can’t make the worst-case planning topology better. It’s that simple.

The only apparent use of dynamic line ratings in planning would be this scenario: Assume multiple potential solutions to a reliability violation. Maybe a more expensive solution would be better if its incremental production cost savings outweigh its incremental solution cost. The odds of this happening in practice are slim to none, and Slim left town.

Transmission line ratings that are relevant to planning, including generator interconnection, are unique emergency (contingency) ratings. In its December rulemaking requiring use of ambient-adjusted ratings, FERC also required unique emergency ratings for operations/dispatch, but did not do so for planning/interconnection studies.[3]

But the latter is what matters to save consumers from transmission overbuild, and to save renewable generators from unnecessary costs and delays. FERC did not address the expert engineering comments in that proceeding,[4] creating the irony of higher emergency ratings for operations than for planning.

FERC did not address this subject, yet again, in this NOPR.

Other ‘Grid Enhancing Technologies’

The NOPR also mandates consideration of other “grid enhancing technologies,” which beside DLRs, are specified as “advanced power flow control devices.” As with DLRs, such devices have little, if anything, to do with increasing grid capacity. In looking at the study[5] supposedly supporting the planning/interconnection value of GETs, I can’t find anything relevant. The study at different points refers to planning but then says “GETs focus on operational improvements,”[6] and the value proposition seems limited to improved dispatch.[7] Not planning/interconnection.

What technologies actually do increase grid capacity for planning/interconnection purposes? Technologies that increase physical capacity of grid elements such as those that the Electric Power Research Institute has identified.[8] These include simple things like sag studies to identify possible retensioning and tower raising, and more sophisticated technologies like reconductoring with advanced conductors[9] and applying high-emissivity conductor coatings.[10] None of these are discussed in the NOPR.

Bottom Line

In the worthy endeavor to increase grid capacity and increase renewable interconnections, the NOPR is pushing the wrong set of technologies.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[1] Docket No. RM21-17-000, ¶ 267-277, issued April 21, 2022.

[4] https://elibrary.ferc.gov/eLibrary/filedownload?fileid=020C3BCD-66E2-5005-8110-C31FAFC91712. And I addressed this toward the end of my column in footnote 2.

[6] Slide 23.

[7] Slide 26.

[10] Per an Oak Ridge National Laboratory study of conductor coating: “a coated conductor affords approximately a 20% increase in ampacity when operating at the same temperature as an uncoated conductor.” https://info.ornl.gov/sites/publications/Files/Pub138393.pdf (pdf page 10).

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Alliant Energy Leads Challenge of ITC Midwest Capital Structure

Alliant Energy is spearheading a coalition of utilities, industrial customers and consumer advocates contesting ITC Midwest’s capital structure at FERC.

The Iowa Coalition for Affordable Transmission filed a complaint last month, alleging that the equity ratio used in ITC Midwest’s capital structure is unfair and should be reduced to 53% from 60% (EL22-56).

The coalition includes Alliant subsidiary Interstate Power and Light (IPL), the Iowa Office of Consumer Advocate, the Resale Power Group of Iowa, the Iowa Business Energy Coalition and the Large Energy Group, a group of IPL major electric service customers.  

The coalition argued that since FERC accepted ITC’s current capital structure in 2007, “ITC Midwest and MISO have changed substantially.” It said Midwest’s rate base grew by 550% since 2007 “to the point that network and firm point-to-point transmission rates are over 275% higher than the average rates of other transmission owners.”

“Financially, ITC Midwest and its affiliates performed strongly for their investors, so much so that their parent, ITC Holdings Corp. was acquired by Fortis Inc. [in 2016], an international public utility holding company,” they wrote.

The coalition argued that ITC no longer meets the commission’s three-part test to ensure a capital structure won’t result in excessive costs for consumers. It said ITC Midwest doesn’t have its own credit rating separate from ITC Holdings and Fortis, and that its parents effectively guarantee its debt. The group also said ITC Midwest’s 60% common equity ratio “significantly exceeds those set by recent FERC orders and the equity ratios of publicly traded proxy companies.” Thy said it is “excessively skewed toward equity.”

“This conclusion is based on evidence including ITC Midwest’s complete lack of any management-level employees of its own — all of its officers are officers of ITC Holdings — and evidence indicating that debt rating agencies look to ITC Holdings and Fortis when evaluating ITC Midwest’s creditworthiness,” the coalition said.

The group’s suggested 53% is the median of other MISO transmission utilities with similar bond ratings.

“Fifteen years ago, when ITC Midwest was first created to acquire IPL’s transmission system … ITC Midwest had no track record of transmission ownership or investment; it did not even have its own credit rating — FERC approved its capital structure proposal based on an expectation that ITC Midwest would have its own credit rating separate from its parent company,” the coalition said.

The Iowa Utilities Board and the Minnesota Department of Commerce took notice of the complaint and wrote to FERC in support of it.

“ITC Midwest owns transmission in Minnesota, and therefore its existing capital structure and transmission rates have direct implications for Minnesota ratepayers. In addition, the equity ratio issue raised has important long-term implications for Minnesota ratepayers as transmission owners in Minnesota and throughout the MISO region consider adding significant amounts of new high-voltage transmission into their rate base,” the Minnesota Department of Commerce said.

The North Iowa Corridor Economic Development Corp. also sided with the complaint, noting that high energy costs have detracted from potential economic development in the area.

“Our organization has seen directly how higher energy costs here have led local and prospective businesses to choose other locations for expansion,” it said.

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Mayflower Wind Interconnection Change to Reduce Power Price 10%

Mayflower Wind is seeking to amend an 804-MW offshore wind power purchase agreement with Massachusetts’ utilities to reflect a change in the project’s interconnection point to land. The new location will allow Mayflower to reduce the original project bid price by about 10%.

The joint venture of Royal Dutch Shell (NYSE:RDS.A) and Ocean Winds North America, itself a joint venture of EDP Renewables and ENGIE, wants to interconnect the project at Brayton Point, about 50 miles west of the original interconnection point on Cape Cod, according to May 25 testimony to the Massachusetts Department of Public Utilities by Katherine Wilson, manager of long-term clean energy supply at National Grid (Dockets 20-16, -17, -18).

Eversource Energy (NYSE:ES), National Grid (NYSE:NGG) and Unitil (NYSE:UTL) selected the project in a 2019 OSW solicitation, and the department approved the utilities’ PPAs in 2020 for an initial 408-MW phase and a second 396-MW phase.

A change in the project’s interconnection point stems from the developers’ winning a 405-MW project bid in the state’s latest OSW procurement round last year, which includes interconnection at Brayton. Mayflower plans to build common offshore transmission infrastructure to serve the 804-MW project and the 405-MW project, Wilson said. Doing so, she added, would enable other project interconnections at the original site on Cape Cod, where ISO-NE has determined that only up to 1,200 MW of interconnection capacity is available based on planned system upgrades.

The two projects that Mayflower plans to interconnect at Brayton are in a 127,000-acre lease area (OCS-A 0521) that the developers say has 2 GW of generation potential.

Mayflower’s PPAs for the two phases of the 804-MW project allowed for a maximum price of $77.76/MWh, with potential to adjust the price down based on the developers’ ability to qualify for investment tax credits in the future. The maximum price is based on Mayflower receiving a 12% tax credit, and the PPA allowed for a minimum price of $70.26/MWh should a change in law provide for a 30% credit.

By combining the interconnection points at Brayton, Mayflower said it can lock in a price of $70.26/MWh, thereby eliminating ITC uncertainty. Currently, OSW projects that begin construction by the end of 2025 are eligible for a 30% ITC.

Mayflower’s change to the interconnection includes delaying the commercial operation dates (CODs) for the two phases of the 804-MW project by 18 months, according to a joint motion to amend the PPAs filed by the utilities. The CODs for the two phases would change from February 2026 to September 2027, and from June 2026 to December 2027, respectively.

Eversource, National Grid and Unitil filed a petition May 25 with the DPU (Docket 22-72) for approval of a PPA with Mayflower for the 405-MW project awarded last year. Under that PPA, Mayflower would place the project into commercial operation in March 2028.