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November 7, 2024

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Lithium-ion Batteries to Replace NYC Peaker Plant

An energy storage developer has committed to replacing one of New York City’s aging fossil-fired peaker plants with a lithium-ion battery system. 

Elevate Renewables said it expects its Arthur Kill project to be the largest battery energy storage system (BESS) in the city when completed in mid-2025.  

This distinction speaks more to the historic challenges of siting storage in the city than to this project’s capacity — at 15 MW and 60 MWh, it is a fraction of the size of systems being built elsewhere in the state and nation. 

However, New York City has moved to sharply ease construction of energy storage, which will play a critical role in decarbonization of its grid, and Elevate Head of Development Eric Cherniss said he expects his team’s project will not hold the title for long. 

But he’s OK with that and says down the road Elevate may make plans of its own that also would dwarf this initial project. 

“New York has a very aggressive target. And I think we can play a very material role in that,” Cherniss said. 

The corporate umbrella that includes Elevate owns the Arthur Kill Power Station, which along with the peaker consists of two gas-fired steam turbines rated at 376 and 535 MW and dating to 1959 and 1969. 

One can think of potential scenarios involving an aging waterfront fossil plant with interconnection rights in a state trying to develop 9 GW of offshore wind on its way to a zero-emissions grid.  

Nothing is ready for public announcement at Arthur Kill, Cherniss said, “but we definitely see that there’s opportunities to reutilize existing infrastructure.” 

The City of No

Development of BESS has been slow in New York state, due in part to market and regulatory structures not optimized for storage. Development has been particularly challenging in New York City, which had earned the nickname “City of No” for its approach to renewable energy development. 

With its dense population, expensive real estate and public safety concerns, the city has practical limits on renewables beyond policy limits. 

But in December, the New York City Council approved a package of zoning changes titled “City of Yes for Carbon Neutrality” that seeks to ease siting of energy storage and renewable energy generation, along with other environmentally friendly steps. 

The Arthur Kill BESS proposal had been in the works for a few years and did not face some of the obstacles that stymied other projects.  

It is in Staten Island, the city’s least populated borough, and will sit on a legacy brownfield site already used for power generation in an industrial area apart from homes. 

This is Elevate’s niche: The 4 GW of projects it is developing in six states are all co-located with existing power infrastructure on brownfields, whether they are replacement, co-location or hybridization of new and existing assets, Cherniss said. 

This cuts down on environmental impact, can reduce local opposition and may come with a skilled workforce on site. 

“It’s just the right place to put these facilities and be able to provide the services that are wanted in places in which they’re needed,” he said. 

“So, we had a lot of things going for us when we initiated this development that helped speed things along and reduced the risk of execution.” 

The 20-MW gas-fired peaker the BESS will replace was destined for retirement anyway — it will not meet tougher state air emissions standards imposed on peakers effective May 1, 2025. 

The upcoming wave of peaker retirements was sufficiently worrisome to NYISO that in November, it directed four of the generators to remain available for up to two more years to meet reliability needs. 

The Arthur Kill BESS will be one more backstop, able to power more than 10,000 households during peak periods — not a large number in a city of 8.3 million people, but it makes a statement.  

“It demonstrates the capability of renewables and specifically energy storage to really just step into the void associated with retiring assets,” Cherniss said. 

All major regulatory hurdles are cleared: Elevate has signed its construction contracts, and the energy storage services agreement with Con Edison was submitted to the state Department of Public Service on May 24. 

Commercial operation is targeted for the summer of 2025. 

The City of Yes

In the wake of the City of Yes revisions, Staten Island has attracted attention of BESS developers, so much so that Borough President Vito Fossella has raised safety concerns about the number of proposals and their proximity to residential areas. 

Popular opposition has reared up as well, thanks in part to media coverage of BESS fires. But in the industrial zone along the Arthur Kill, the new BESS will be away from residences. 

Cherniss said Elevate has heard no local opposition to its 15-MW BESS. 

Similarly, a 650-MW BESS proposed by Hecate Grid a half-mile from the Arthur Kill Power Station has generated no written comments to the DPS even though it is closer to residential areas, nor did anyone comment during a DPS public statement hearing May 15. 

Other large-scale proposals have been floated in New York City, and Cherniss predicts the Arthur Kill BESS will not be the largest in the city for long. 

“It really depends on when people show up with their projects based on their stated time frames,” he said.  

“I believe it’s sometime in either ’26 or ’27. For New York City, I hope that it’s sooner or it stays on that time frame, because I’d love for there to be some more competition to continue to grow energy storage due to the importance that I see, placed in the overall transition.” 

(These records already are falling with some frequency: Less than a year ago, Con Edison claimed the title of biggest BESS in the city with a 7.5-MW/30-MWh facility in a different part of Staten Island.) 

Elevate “absolutely” intends to go larger than 15 MW on future New York City BESS development, Cherniss said, and he sees progress at the DPS and NYISO on building regulatory and market structures that can better support energy storage development. 

Storage is more than a way of meeting peak demand, he said; it adds stability and resilience to a grid increasingly relying on intermittent renewables. These added values are not presently compensated, he added, but he sees improvements in the works in New York state.  

“It’s going to take the market some time to figure out how to give those signals to the development community,” he said, “and that’s why you see a significant number of the states either putting procurement requirements or direct subsidies, because they know the value of energy storage, but they know that the market isn’t necessarily giving that clear of a signal.”

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NJ Master Plan Speakers Seek Sweeping Electrification Plan

Clean energy supporters argued in a hearing for the next New Jersey energy master plan that an aggressive and broad embrace of electrification would generate enough money to help fund clean energy projects and protect ratepayers. 

Speakers at the fourth, and final, online public forum, held June 3 by the New Jersey Board of Public Utilities (BPU) to solicit input for the successor to the state’s 2019 Energy Master Plan, pushed state officials to include extensive investment in storage and in-state electricity generating projects in the plan. 

They also sought a cost evaluation that would include the direct expenses of electrification strategies and show the costs avoided if the effects of climate change and pollution are mitigated, such as fewer health services needed. Some speakers argued that electrification strategies would pay for themselves. 

Andy Wall, a board member of the Mid-Atlantic Solar and Storage Industries Association, said that instead of spending $600 million to buy clean energy from out of state, as the organization forecasts for this year, the state should invest within its own borders. 

“We need to take those resources and focus them on clean energy generation projects closer to home that actually matter to our own in-state generation mix,” he said. 

He said while the state goal for 2023 was for clean energy to account for 22% of all energy, only about one-third of that was generated in state. The rest “came from renewable energy projects in the Midwest, mostly Illinois, but also Indiana, Ohio, even North Dakota and some other places on average 800 miles away. “  

Michael Winka, a former BPU clean energy policy adviser, said the state’s electric system generates about $11 billion in revenue, which would increase to $22 billion if electricity use doubled as forecast. That would provide plenty of money to support the energy transition, he said. 

“The cost to upgrade the distribution system at max is probably $4 billion to $5 billion range,” he said. 

Winka called the 2019 master plan a “good first step” but said the next version has to better evaluate all energy systems and provide a “detailed cost, avoided cost and benefits, of not using oil, gasoline and diesel.” The plan also should “detail the revenue increases that go along with an increase in electricity usage.” 

Deeper Study

BPU officials said they’re looking to produce a “deeper more robust study,” than the 2019 version, which was compiled at the request of Gov. Phil Murphy (D). While it has underpinned much of the state’s clean energy strategy during Murphy’s tenure, business groups have criticized the plan for failing to include an assessment of the cost of dramatically cutting fossil fuel use. 

The next plan, state officials said, will include policy analysis and a review of best practices nationally, modeling of the impact of the plan on gas and electricity rates and a consideration of using gas as a backup heat source in the coldest months of the year. (See NJ Wrestles with Clean Energy Priorities.)   

With the public hearings completed, the BPU will conduct “workshop-style gatherings of stakeholders.” The agency plans to release a report draft in the third quarter of 2024 and the final report in the fourth quarter. According to the BPU, the report will be led by the Governor’s Office of Climate Action and the Green Economy, with input from multiple state agencies. A Final Comprehensive Climate Action Plan will be released in the third quarter of 2025. 

More than 50 people spoke over three hours at the first session, on May 20, and about two dozen voiced their opinions at the final hearing. Among the speakers June 3, Andrew Gold, staff attorney for the New Jersey Rate Counsel, offered a note of caution, urging the master plan drafters to “view modeling results with a healthy degree of skepticism.” 

“Projecting the future during fundamental changes over long periods is challenging,” Gold said. “Modeling results are frequently overly optimistic and make many assumptions that are impractical to implement.” 

He said the BPU should compare the 2019 master plan modeling assumptions to what happened and ensure the 2024 energy master plan incorporates the past. Gold urged the BPU to make its “modeling platform” public, calling it “unreasonable to ask ratepayers to pay billions of dollars based on a model that the public cannot access.” 

At the BPU’s May 22 master plan hearing, the Division of Rate Counsel said state energy efficiency programs, many of which are focused on helping low- to moderate-income ratepayers, should be more cost effective and the state should hold “utilities and contractors accountable for their performance.” Some programs should be run by utilities and others by the BPU, said Lisa Littman, assistant deputy rate counsel, who urged the board to “refrain from establishing utility-run monopolies.” 

Solar-powered Green Hydrogen

Utilities emphasized the need for planning, and support for their own initiatives, some of which are underway. 

“Comprehensive integrated distribution planning is vital and will help identify utilities’ resource and customer needs,” said Noreen Giblin, associate counsel state regulatory at PSE&G. 

“Improvements to regional load forecasting are essential for effective transmission planning, and in determining how much generation needs to be built and where, while providing visibility into the amount of clean generation needed to reach stated objective,” she said.  

Giblin urged the state to strengthen programs to boost medium- and heavy-duty vehicle infrastructure. And she said PSE&G has proposed “the adoption of time use rates in its current base rate case to …. encourage residential customers to shift electricity usage away from peak demand times, saving money.” 

Melissa Orsen, senior vice president at South Jersey Industries and president of SJI Utilities, which owns two gas utilities in new Jersey, said the company aims to reach 100% carbon-neutral operation by 2040. The effort includes spending 25% of the utility’s annual capital expenditures on sustainability projects such as repairing leaks, replacing the legacy pipeline distribution system with “modern resilient facilities” and investing in renewable natural gas (RNG) and green hydrogen. 

“We envision a future where New Jersey residents transition to clean energy but continue to use their gas appliances with RNG and green hydrogen being critical components of the gas stream,” she said, adding that “our ability to achieve these goals in many ways depends on the state support as expressed in the next EMP.” 

The utility’s effort also will depend on how the BPU responds to utility on-site solar projects, she said, adding that this year, it will begin “producing green hydrogen powered by solar energy” in South Jersey that will be blended into the gas system. 

Solar Parity with Wind?

Clean energy developers said the state needs to do more to ensure their sectors become the major energy providers needed to meet state clean energy goals. 

Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said he would like to see the state reform the “stark disparity in the state’s investment of effort and money to help the offshore wind industry with infrastructure investment, flexibility, workforce development, helping hand in tough times and much more.” 

“We recognize the absolute necessity of offshore,” he said. “But we want to see an equally comprehensive and proactive approach for solar.” 

In a subsequent interview with NetZero Insider, Rawlings said the issue is a “long-standing gripe that we’ve never spoken about.” He said his concerns include the amount of money the state has committed to offshore wind infrastructure while it has “never spent a dime on infrastructure to encourage solar.”  

Another concern, he added, is that in the post-pandemic period — when developers experienced cost increases and supply chain issues — the BPU refused to extend project deadlines, resulting in “hundreds of projects that had to be canceled before they were done.” 

Evan Vaughan, executive director of the Mid-Atlantic Renewable Energy Coalition, which represents 50 utility scale wind, solar and storage developers, said the state needs to address the fact it is “woefully behind” in its energy storage goals, specifically the goal of having 600 MW of storage in place by 2021 and 2000 MW of storage in place by 2030. 

“The PJM market does not incentivize energy storage currently, and so a state incentive program is critical for any meaningful level of deployment,” he said. He encouraged New Jersey to conduct long-term planning for its transmission system, including with other states. 

“We ask New Jersey to look closely at near-term opportunities to coordinate with neighboring states like Maryland and Delaware to facilitate no-regrets cost-saving transmission planning for offshore wind integration and for the integration of other energy sources like solar and storage,” he said. 

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MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing

MISO said new queue entries must wait while it takes another swing at imposing an annual megawatt cap on its interconnection queue.  

MISO Manager of Generation Interconnection Ryan Westphal said the RTO will file by the end of the year for a cap to create a leaner and less backlogged waiting room for new generation. He said it won’t accept applications for new generation projects until it hears from FERC on the filing. That likely will leave MISO a year behind on its queue processing.  

“Our plan right now would be to get this through before we open another queue,” Westphal told stakeholders during an Interconnection Process Working Group teleconference June 4.  

Months ago, MISO staff hoped the RTO could begin processing both the 2023 and 2024 cycles of queue applications before the end of the year. That no longer appears to be the case. When asked by stakeholders, Westphal wouldn’t venture an estimate as to how long before MISO would begin study work on the 2024 cycle of interconnection requests.  

MISO’s 2023 class of queue applications was delayed into early 2024 while it tried for new rules to discourage speculative projects from entering the queue. Those rules included its unsuccessful first attempt at a megawatt cap. (See MISO Reports 123-GW Roster for 2023 Interconnection Queue Cycle.) In April, MISO reported a 2023 queue intake of 123 GW spread across about 600 interconnection requests, substantially lower than 2022’s 171 GW of proposed generation projects across 956 interconnect requests. 

FERC late last year denied MISO’s proposal to cap generation projects entering its interconnection queue on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits from limiting new generation onto the grid. However, FERC said a “cap in some form could be beneficial.” (See FERC Rejects MW Cap, Approves MISO’s Other Stricter Interconnection Queue Rules.) 

MISO maintains that some limit on projects remains necessary. It said too many applications result in an overwhelming study process and make it nearly impossible to resolve models for a hypothetical system loaded with new generation.  

“We did get a 30% reduction in the 2023 cycle versus 2022, but we still think we need to cap annual cycles. … We think this is necessary for the future to maintain an orderly queue going forward,” Westphal said. “Ultimately, we want to have a queue that’s fast and efficient where [we’re] giving you good information so you can make better decisions. That’s the hope, and we think that’s achievable with less volume.” 

Westphal said that, had MISO this year encountered the volumes it experienced in 2022, the queue could be as high as 350 GW by now. He emphasized that MISO’s peak load expectation is 127 GW.  

Westphal said MISO is leaning toward simplifying the calculation, which could be as “simple as a percentage of load.” He said MISO staff are at the same time contemplating ways to “limit the use of exemptions” to the cap to better the chances of it passing FERC’s judgment.  

Finally, Westphal reassured stakeholders that MISO is thinking about its future resource adequacy needs alongside its second attempt at a cap design. He said MISO envisions that a cap would put it in position to administer less onerous studies more quickly and deliver more interconnection approvals sooner. 

Curb ‘Queue Crashing,’ Savion Advises

However, Derek Sunderman, of Shell subsidiary Savion, said that instead of a hard megawatt cap, MISO should pursue a “gating mechanism” to deter disproportionate applications from a handful of interconnection customers.  

He said some interconnection customers will “queue crash,” or submit large volumes of interconnection requests into a study application window to secure grid hookups.  

Sunderman said MISO should consider administering a volumetric price escalation in the queue, where interconnection customers’ fees and penalties rise as they submit more projects for study. He said higher milestone fees for 4 GW worth of applications versus 1 GW of submittals would allow smaller interconnection customers to meaningfully participate in the queue while still allowing larger interconnection customers to submit as many projects as they believe feasible. He also said escalating prices would cause large corporations to rethink their projects’ viability.  

Sunderman said if MISO pursues a hard cap at a hypothetical 80 GW, it might encourage a mad dash among developers to snap up queue positions. Volumetric price escalation, on the other hand, would allow all kinds of developers access, he said.  

“It’s not a fight of the fittest of who can consume the most megawatts first,” Sunderman explained. “We’re concerned that the higher-equipped companies could control a percentage of the queue” under a hard cap.  

Westphal said MISO would consider Savion’s proposal and hold more discussion on a cap design at the Interconnection Process Working Group’s meeting July 23.  

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Maryland Governor Creates Climate Subcabinet

Maryland Gov. Wes Moore (D) signed a sweeping executive order June 4 calling for the state to establish a zero-emission heating equipment standard and a new clean heat standard to be added to the state’s Renewable Portfolio Standard. 

The order also calls for formation of a Governor’s Subcabinet on Climate, which will oversee the efforts of other state agencies to implement the state’s Climate Pollution Reduction Plan, released in December 2023, which is the state plan for implementing the Climate Solutions Now Act of 2022.  

The law committed the state to cutting its greenhouse gas emissions by 60% by 2031, and Moore also has set a 2035 target for the state to power itself with 100% clean energy. Under the order, the Maryland Energy Administration will develop a framework for a clean energy standard to achieve the 2035 goal and “determine if all or part of the proposed clean energy standards can be implemented through existing authority.” 

The executive order notes Maryland has seven years to reach its 2031 goal for emissions reduction and that both short- and long-term investments will be needed to address climate change. 

Speaking at the signing ceremony, at Henderson-Hopkins School in Baltimore, Moore called the executive order “one of the most comprehensive executive orders on climate of any governor in Maryland’s history. … It is bold; it is ambitious; and Maryland, we’re going to get it done because that’s what we do. … 

“We cannot just talk about climate action in the realm of what are we doing to avoid catastrophe,” Moore said. “It’s always about what are we doing to unleash opportunities.”  

The order calls for a “whole-of-government” approach to climate action, including:  

    • Maryland will work with the other states in the Regional Greenhouse Gas Initiative (RGGI) to set a new regional cap for carbon dioxide emissions from power plants that “is aligned with Maryland’s and partner states’ clean energy goals.” RGGI is a regional cap-and-trade program that sets carbon dioxide emission caps and holds quarterly auctions for emission allowances covering 11 New England and mid-Atlantic states, including Maryland.  
    • By Nov. 1, individual state agencies will be required to submit Climate Implementation Plans on the actions, time and resources they will need to meet the goals of the Climate Pollution Reduction Plan. The subcabinet will submit a progress report on implementation of the plan by Dec. 1 of this year and every following year.  
    • The state Department of Transportation will upgrade its plans for deploying electric vehicle chargers funded by the federal National Electric Vehicle Infrastructure (NEVI) program and develop a new “multiagency strategy to build out Maryland’s vehicle charging infrastructure.” 

Immediate reactions from clean energy and environmental justice advocates were uniformly positive. 

“Burning fossil fuels in our buildings is a major source of greenhouse gas emissions in Maryland,” said Josh Tulkin, director of the Maryland chapter of the Sierra Club. “By developing zero-emission heating equipment standards this year, Maryland can make a measurable dent in climate pollution while delivering cleaner, healthier air for residents.”  

“Today’s announcement from Gov. Moore not only cements Maryland’s legacy as a climate leader but will create more equitable access to climate and health resources, paying dividends for generations to come,” said Ruth Ann Norton, CEO of the Green & Healthy Homes Initiative. “Phasing in zero-emission heating equipment standards, coupled with policies that build healthier, more affordable homes, will provide urgent relief in the form of cleaner, healthier air for low-income families and a future where all Marylanders can thrive.”  

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SPP: Enough Generation to Meet Summer Demand

SPP said June 3 it expects to have enough generation to meet energy demand despite higher regional temperatures this summer, sharing the same message it did earlier with stakeholders.

Staff speaking at the RTO’s biannual Emergency Communications User Forum on May 21 said SPP’s biannual seasonal assessment showed the grid operator has a 90% probability of being equipped to serve all loads during summer peak usage hours. The assessment indicates summer operations should be normal with no extreme operational situations.

Meteorological models predict a 33 to 50% chance of above-normal temperatures this summer at varying levels in the 14-state SPP footprint. Similar percentages exist for below-normal rainfall in its region, the RTO said.

“While we anticipate no major concerns this summer, we are prepared for any circumstance,” SPP’s Bruce Rew, senior vice president of operations, said in a press release. He added the RTO is confident “in our ability to keep the lights” on despite a forecast of higher-than-normal temperatures.

SPP says it has the systems, tools and procedures in place to mitigate risks and maintain reliability should extreme weather, unexpected outages or other events affect the region. It can call on generating units to commit to run earlier or more often than usual, delay planned outages, import energy from neighboring systems or tap into available reserves.

NERC’s 2024 Summer Reliability Assessment found SPP will have sufficient operating reserves this summer. It projects peak demand could hit 56.32 GW and estimates an anticipated reserve margin of 27.8%. The RTO set an all-time coincident peak of 56.84 GW last August.

SPP has over 101 GW of nameplate capacity. It had 62.16 GW of accredited capacity last year.

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FERC OKs MISO Settlement Rules for Widespread Tx Outages

FERC on May 31 ruled MISO can apply new settlement practices to generators physically disconnected from the grid during extensive transmission outages triggered by extreme events.   

The commission’s order allows MISO to adjust settlements when extreme events cause significant forced transmission outages that sever generation from the grid. Under the change, the RTO now can reflect in settlements the involuntary nature of a disconnection through a “forced-off asset” designation and block generators from excessive penalties or payments (ER24-1191).  

The revisions went into effect June 3. MISO sought FERC’s approval for the rules before the RTO’s South region enters the Atlantic hurricane season.  

MISO’s scarcity pricing setup assumes lines are intact and operational, with market participants having physical capability to respond to price signals by reducing demand or ratcheting up supply.  

However, MISO said the “always connected” assumption doesn’t reflect the reality of cases like Hurricane Laura, when parts of the transmission system were destroyed. In those cases, MISO said it’s “inappropriate and inequitable” to levy performance penalties on disconnected generators unable to meet their day-ahead commitments by forcing them to “buy back their day-ahead committed energy at dramatically higher real-time prices.”  

On the other hand, MISO said it’s equally unfair to “compensate involuntarily disconnected load as if it responded to real-time scarcity pricing and then pass off the cost of such windfall compensation to other market participants through uplift.”  

MISO plans to use its day-ahead LMPs prior to the event to retroactively settle excessive penalties or excessive windfalls for knocked-off assets.  

FERC agreed MISO’s plan will mitigate “substantial financial impacts without any corresponding operational benefits” in circumstances when multiple transmission outages prevent market participants from responding to price signals.  

“We find that the proposed revisions would provide MISO with reasonable discretion to mitigate the unintended consequences of scarcity pricing during extreme events by evaluating individual facts and circumstances,” the commission added.  

MISO said the revisions won’t apply during emergencies when the transmission system remains intact. It will require at least 10 transmission outages and a 10% increase in dead or disconnected pricing nodes before conditions are met to use the forced-off designation. It also pledged to declare forced-off asset events no more than two weeks after they occur.  

If necessary, MISO will adjust settlements for resources in the path of the event that were cleared in the day-ahead market but couldn’t inject for at least six dispatch intervals. It also will make adjustments for load zones in the area with fully or partly forced-off loads and to virtual transactions associated with pricing nodes in the area that cleared in the day-ahead market.  

MISO adviser Chuck Hansen has said events need to be “widescale” to activate the knocked-off designation, such as a weather disaster, geomagnetic event or cyberattack. The RTO expects such events will be rare. The status would not apply to assets that respond to MISO-directed load shedding.  

The settlement rule change is part of MISO’s ongoing effort to improve its scarcity pricing.  

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Offshore Wind Projected to Save New Englanders $630M per Year

A new analysis prepared for the Sierra Club concludes offshore wind energy would be a money-saver for New Englanders, despite the high cost of construction. 

The six-state region relies heavily on natural gas for power generation, the report explains, and the cost of gas can be quite high, particularly in winter. 

“Charting the Wind” projects that bringing 9 GW of offshore wind online would save $2.79 or $4.61 per month per average residential customer, depending on whether a midrange or high-price gas scenario is used. The total would be $630 million in an average year in the midrange model, the authors write. 

Synapse Energy Economics, which prepared the report, notes there are additional benefits to be gained by shifting from natural gas generation, beyond the savings on utility bills. 

These include the climate and public health improvements yielded by reducing the power sector’s emissions of carbon dioxide, nitrogen oxides, sulfur dioxide and fine particulate matter.  

Also, the average $3 billion spent per year to buy natural gas for power generation in New England goes out of the region. Slashing gas use could keep a significant percentage of that money in the regional economy. 

The Sierra Club, a proponent of offshore wind energy, commissioned the report to counter some of the criticism being leveled at the offshore wind industry as it gains a foothold in U.S. waters — particularly after multiple projects from Massachusetts to Maryland were sidelined or canceled in the past year because of soaring costs. 

“Opponents of offshore wind argue that building out offshore wind infrastructure is too expensive, often without any empirical support for that contention,” Sierra Club staff attorney Sarah Krame said during a news conference June 4. “Recent increases in the cost of offshore wind and the cancellation of contracts for development of offshore wind have further raised questions about the costs and benefits of this renewable resource.” 

Synapse Vice President Melissa Whited said the authors specifically chose the highest recent construction cost as their baseline for calculating the savings for New England offshore wind, even though they hope the current financial pressures will moderate as the industry matures in the United States. 

(That would be $150.15/MWh, the weighted all-in cost of the two most recent contracts agreed upon in New York — Ørsted’s Sunrise Wind and Equinor’s Empire Wind. See related story, Empire, Sunrise Wind Back Under Contract in NY.) 

To calculate a savings of $2.79 or $4.61 per month for each New England family, Synapse modeled 9 GW of wind power feeding into the grid and performed a regression analysis of its impact on supply and demand curves.  

Wind through turbine blades is free, but natural gas prices fluctuate sharply, particularly in New England, where as much as 35% of the supply is imported LNG on peak days. 

“So, once we conducted this regression analysis, we found that adding all that offshore wind and shifting the supply curve would drop the price between 45 and 60% depending on the year,” Whited said. “And we use 23 historical weather years to account for that variation.” 

Josh Berman, a senior attorney with Sierra Club’s environmental law program, pointed out an important confluence of factors: Offshore winds blow strongest in winter, when gas constraints are highest in New England. 

“In addition, on a daily basis, offshore wind is highly complementary to solar power, having its lowest output in the middle of the day when solar generation is high and having higher operation at times when solar power is less available,” he said. 

NetZero Insider asked about the savings calculation. New York state projects Sunrise and Empire would cost utility customers an extra $2.09 a month on average, while the New England report projects monthly savings of $2.79 or $4.61 per customer using the same $150.15/MWh construction cost estimate. 

The answer is volatility, or lack of it. 

“You have different markets and different structures of those markets,” Whited explained. “We also are more gas-constrained in New England. And so what we see is during the winter when the pipelines are operating at capacity, we have very expensive generators and oil-fired generators coming online, and the wholesale electricity market prices just skyrocketing in New England.” 

She added: “You get a slightly different effect, a slightly more muted effect in NYISO because they have a different supply curve.” 

Recent history holds an example in New England that might challenge the savings model projected. 

Rhode Island Energy managed an offshore wind solicitation for Rhode Island in mid-2023, when the cost and supply chain crises were worsening. Only one proposal was submitted, and it was rejected as too costly for ratepayers. (See Rhode Island Energy Rejects Revolution Wind 2 Proposal.) 

Whited said she did not know what the proposed cost of that project would have been. 

In response to multiple contract cancellations along the southern New England coast and the offshore wind industry’s struggles, Connecticut, Massachusetts and Rhode Island joined in October 2023 for the first-ever multistate solicitation, seeking proposals for 6,000 MW of capacity. 

Projects totaling 5,454 MW were submitted by the March 27 deadline for bids. No decision has been announced on the proposals, and no indication has been offered regarding whether the construction costs would be more or less than $150/MWh. (See New England States’’ OSW Procurement receives 5,454 MW in Bids.) 

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Empire, Sunrise Wind Back Under Contract in NY

Two offshore wind projects have rebounded from the financial turmoil of 2023, finalizing replacement contracts with New York for 1,734 MW of capacity. 

Empire Wind 1 and Sunrise Wind were among a flurry of contract cancellations from Massachusetts to Maryland in the past year as costs soared to the point that construction became untenable. The two New York contracts announced June 4 are informed by the setbacks of the past year, in which developers recorded billions of dollars in impairments and government managers saw development pipelines built over the course of years shrivel in a matter of weeks. 

Importantly for the state, Empire and Sunrise are mature proposals, with key approvals in hand and onshore construction already underway. If built as planned, they will be the largest power generation projects in New York in more than a third of a century and an important piece of the state’s decarbonization and economic development strategies. 

“New York is leading the nation to build the clean energy industry, create good-paying jobs and advance our climate goals,” Gov. Kathy Hochul (D) said in a statement. “Offshore wind is a critical piece of our clean energy blueprint to address the climate crisis, and our investments are building a healthy, sustainable New York so that future generations can thrive.” 

New York has a 2035 goal of 9 GW of installed offshore wind. 

South Fork Wind gave the state its first offshore electricity. What it lacks in size — 132 MW — it makes up in bragging rights as first utility-scale project completed in U.S. waters. 

Lengthy History

Equinor/bp and Ørsted/Eversource Energy were awarded contracts for Empire and Sunrise, respectively, in New York’s 2018 solicitation.  

Inflation and interest rates soared in 2022. The two sought increased compensation from the state in June 2023, had their request rejected in October, were invited to rebid in November and were awarded tentative contracts in February. Those contracts are now finalized. 

Empire Wind 1 has a contracted nameplate capacity of 810 MW and is expected to generate first power in 2026. It received the green light from the U.S. Bureau of Ocean Energy Management in November. Equinor has begun rebuilding the South Brooklyn Marine Terminal as a hub for its own projects and for the industry. 

Equinor and bp have severed their partnership, giving Equinor sole ownership of Empire. It is looking for a new partner and expects to make a final investment decision on the project later this year. 

“Empire Wind 1 is a defining project for Equinor, and the [purchase and sale agreement] is an important milestone in de-risking and ensuring a robust path forward as we work toward delivering first power,” Molly Morris, president of Equinor Renewables Americas, said in a statement. 

Sunrise has a contracted nameplate capacity of 924 MW and also is expected to generate first power in 2026. Ørsted and Eversource announced their final investment decision in the project in late March, on the same day BOEM gave Sunrise the green light. Onshore transmission infrastructure work already has begun. 

Award of a final contract is one of the milestones that would trigger Ørsted’s buyout of Eversource’s half of the Sunrise project. Others — FERC and BOEM approvals — are yet to come. 

The new contracts carry a sharply higher upfront cost for ratepayers along with the promise of an unquantifiable societal benefit from decarbonizing the grid and billions of dollars in economic activity. 

The original contracts had an all-in average development cost of $83.36/MWh in 2018 dollars, with an average residential monthly bill impact of 73 cents. New York said the new contracts carry a weighted average all-in lifetime development cost of $150.15/MWh, with an average monthly bill impact of $2.09. 

This story was updated with additional information about the Ørsted-Eversource partnership.

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Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats

Stakeholder groups submitted comments to FERC last week in support of ISO-NE’s proposal to create a new longer-term transmission planning (LTTP) process to facilitate more forward-looking transmission investments to meet looming needs (ER24-1978). 

The new process was developed with the New England States Committee on Electricity (NESCOE) and features a default cost allocation method in which costs can be regionalized if the project is expected to bring net benefits. 

LTTP requests for proposals would be issued by ISO-NE at the request of NESCOE, and the RTO would evaluate and select a preferred solution. States then could submit an alternative cost allocation method or decide to terminate the process. (See NEPOOL TC Approves Process for States’ Transmission Needs.) 

The proposal also includes a supplemental process for projects that do not pass the cost-benefit threshold; individual states could agree to cover the costs in excess, while the remaining costs would be regionalized. 

ISO-NE filed the proposal with FERC prior to the commission’s Order 1920, which requires transmission providers to plan at least 20 years into the future, evaluate solutions with a set list of criteria and establish a default cost allocation method to apply if states are unable to reach an agreement on cost. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) The commission issued the order May 13; it goes into effect 60 days after its publication in the Federal Register; and compliance filings are due 10 months after that. 

Advanced Energy United, NESCOE, RENEW Northeast, a coalition of climate nonprofits and the Connecticut Municipal Electric Energy Cooperative (CMEEC) all submitted comments in support of ISO-NE’s proposal, applauding the agreement as an important step in proactive transmission planning. 

United wrote that the proposal is “urgently needed,” noting that “the first Order No. 1920-compliant planning cycle will not start for at least two years, with selection of transmission facilities slated to occur three years after that.” 

However, the clean energy trade association expressed concern the proposal “fails to fully leverage the benefits of transmission competition” by tilting the playing field in favor of incumbent utilities. 

“The proposal makes it very difficult for nonincumbents to offer any solutions that require new equipment on a PTO’s [participating transmission owner’s] existing transmission system,” United wrote. 

Nonincumbent transmission owners “are prohibited from identifying or installing new equipment needed for upgrades on existing lines without partnering with the incumbent PTO,” the organization added. 

These concerns were echoed in comments by RENEW and a joint filing by New Hampshire Transmission and LS Power. The latter two argued the proposal makes the same mistakes as an RFP issued by ISO-NE in 2019 to address reliability concerns associated with the retirement of the Mystic Generating Station. Most of the submissions were disqualified for relying on the land of incumbent transmission owners, which ultimately led to tariff changes intended to fix the issue, the companies said (ER22-733). 

“Under the limitations included in the proposal, only an incumbent transmission owner will be permitted to submit comprehensive solutions to identified needs,” the companies wrote, adding that the proposal contains a “a de facto [right of first refusal] for incumbent PTOs.” 

RENEW urged FERC to accept the filing as is but called on ISO-NE to initiate an additional phase of revisions to address the concerns about incumbents. 

In testimony submitted with its filing, ISO-NE said requiring complete solutions would increase “the likelihood of the process successfully leading to development of transmission solutions, rather than having the process terminate because the submitted longer-term proposals cannot be combined in a manner that addresses the identified needs.” 

CMEEC supported the proposal, calling it “a meaningful step towards the more comprehensive planning approach envisioned by the commission.” 

“The selection of projects through competitive solicitation should allow for consideration of transmission solution proposals that feature joint ownership arrangements with consumer-owned utilities,” which could provide “myriad benefits” including financial benefits for ratepayers, tax exemptions, lower cost of debt and reduced siting risk, CMEEC wrote. 

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NIA: Cost, Risk Sharing Needed to Grow Advanced Nuclear Pipeline

Speaking in Waynesboro, Ga., on May 31, Energy Secretary Jennifer Granholm celebrated the completion of Units 3 and 4 at the Vogtle nuclear power plant with a call for the United States to “draw up some more battle plans for more reactors” and triple its nuclear capacity by 2050. 

But according to a new report from the Nuclear Innovation Alliance (NIA), significant barriers remain for moving beyond first-of-a-kind (FOAK) projects like Vogtle to the nearly 200 GW of nth-of-a-kind (NOAK) advanced nuclear projects the U.S. will need to reach that 2050 goal. 

The first new reactors built in the U.S. since 2016, Vogtle’s two units have come online seven years late and $17 billion over budget, leaving subsequent projects surrounded by perceptions of risk, whether real or not, and under pressure to show they can execute on budget and on time. While the Department of Energy is funding a handful of advanced nuclear demonstration projects, “material financial commitments (i.e., signed contracts and spending on project development) to additional projects have been slow in coming,” the report says. 

These projects are generally smaller and use different, more advanced and efficient technologies than the existing 94 reactors at the 54 power plants that make up the U.S. nuclear fleet, which provides nearly 20% of the nation’s power. For example, X-energy, one of the developers receiving federal funds from DOE, is working with Dow to install four 80-MW small modular reactors (SMRs) at the company’s Seadrift, Texas, plant, where it manufactures a range of plastics and other products.  

What’s needed for a healthy pipeline of NOAKs will be a clear set of best practices, accelerated permitting, supply chain buildout and innovative approaches to cost- and risk-sharing for project developers and offtakers, the report says. 

“Faster growth and clean, firm energy is key to the growth objectives of large offtakers” and may make them more willing to accept more development risk, said Stephen Greene, a senior fellow at NIA and author of the report. 

“To accelerate commitments to advanced nuclear, energy offtakers may need to accept a greater portion of the project risks than they do through traditional offtake agreements, such as providing part of the capital commitment to address anticipated costs,” Greene said, speaking at a launch webinar for the report June 3. 

Offtakers sharing costs and risks could receive “compensation later, such as an adjustment to offtake costs or participation in project returns,” the report says. “The most impactful private-sector action would be for offtakers to make capital commitments to provide a backstop of project completion costs,” and the Department of Energy also might chip in to cover at least part of any cost overruns, the report says.  

Kreshka Young, Dow’s North America business director for energy and climate, said her company is financing the upfront development of the X-energy SMRs like any “project in our normal course of our capital planning, and it will go through our normal capital approval process.” 

Dow eventually could look for partners, as offtakers or owners, Young said, but she expects the company’s ownership and business models likely will evolve over time. “But again, at this stage, with the risk levels where they are, the perceptions of risk especially where they are, Dow is today the primary owner of the project.”  

“The real emphasis of the report is how to make projects more attractive to capital markets,” Greene said. “Additional financing either from private-sector participants or from new federal capabilities is a kind of assurance that I think capital markets are going to need, especially for initial projects to address … both the perceived and the real risk of cost overruns.” 

Other topline findings and recommendations in the report include: 

    • Due to the higher costs of FOAKs, the only way these projects pencil out is if they are developed as part of “an intended multi-project deployment plan (through which the cost of early projects can be shared among the projects).” Costs also can be shared via an “order book” of a number of projects of the same design. 
    • In the absence of ongoing, widespread nuclear construction, the U.S. must rebuild its supply chain for new plants, in particular, for the high-assay low-enriched uranium (HALEU) used in advanced and small modular reactors. 
    • Reforms are needed to streamline and speed permitting of new projects at the Nuclear Regulatory Commission (NRC). In a separate overview of potential NRC reforms, NIA noted licensing for advanced and small modular reactors “is challenging because the current licensing pathways have been tailored to conventional, large light water reactors.” 

So far, the NRC has certified the design for only one SMR, the NuScale reactor, and authorized construction of a test advanced reactor developed by Kairos Power, according to the report.  

From FOAKs to NOAKs

Throughout its construction, Vogtle’s repeated delays and cost overruns made the project a point of controversy, particularly for Georgia Power customers who will pick up $7.56 billion of the price tag for finishing the two units. A report in The Atlanta Journal-Constitution estimated that paying off that extra cost could increase utility bills by 10%.   

But with the two units completed and online, Granholm and others at DOE have hailed Vogtle as a major success.  

The expanded plant will be producing roughly 35 million MWh of power per year for the next 80 years, “so that is a multigenerational asset,” said Julie Kozeracki, director of strategy at DOE’s Loan Programs Office, which provided about $12 billion in loans for Vogtle.  

Kozeracki stressed that the lessons learned from the construction of Unit 3 resulted in lower costs and shorter timelines for Unit 4.  

“Many of the challenges faced at Vogtle were true first-of-a-kind issues,” she said. “So, for example, construction began without a complete design, without a mature supply chain, without a trained workforce. But in the course of building Vogtle, we’ve now solved these issues. … 

“Unit 4 was roughly 30% cheaper and more efficient than Unit 3,” she said, and the time needed for testing plant systems went from 94 days at Unit 3 to 42 days at Unit 4.  

“So the worst thing we could do would be to stop after two units,” Kozeracki said. “Vogtle 3 and 4 are a downpayment for everyone to capitalize on.” 

Larger reactors, like the Westinghouse API 1000 reactors used at Vogtle, also can offer economies of scale, which may be particularly attractive to industrial and data center customers looking for large amounts of firm, clean power. 

Many existing nuclear sites have room for additional reactors, she said. Vogtle is the only site in the U.S. with four reactors. “Multi-unit nuclear sites are 30% cheaper to operate than single-unit sites, but we have currently 19 single-unit sites. We have 31 sites with two reactors, three with three reactors … so we have a lot of room to grow.” 

Still, going forward will require a rebalancing of risks, especially for utilities, Kozeracki and Greene said.  

Regulated utilities often cannot recover the high upfront costs of siting, permitting and construction of a new nuclear plant until it goes into operation and “the electricity rates they can charge to customers are not structured to incorporate that degree of risk,” the report notes. 

“Tech companies like Google, Microsoft and Amazon have so much to gain with [nuclear] assets coming online,” Kozeracki said. “And they are growth companies that are in a position to take risk, and they have the cash on hand to take some of that risk. So, I think in order to execute on an effective energy transition, utilities are going to have to learn to become more like growth companies.” 

“The objective is to get over the hump of concerns about risk and get to a point where we’re building these projects more in the regular course,” Greene said. “Then the companies that are building them will have the ability to take those risks.”