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November 27, 2024

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NYISO Proposes Increased Budget, Admin Rate for 2025

NYISO on Sept. 6 presented its $204 million draft budget for 2025 to the Budget and Priorities Working Group, with an administrative rate of $1.319/MWh based on a 154,700-GWh transmission throughput. 

The proposed budget is a 4.72% increase over 2024’s $194.8 million. The proposed Rate Schedule 1 surcharge — the ISO’s administrative fee to recover its operating costs from members — is nearly 3% higher than this year’s $1.281/MWh. The surcharge is billed to all users of transmission lines based on the calculations set forth in NYISO’s tariff. 

“The increase in the revenue requirement for 2025 relative to 2024 is $9.2 million, which is about 4.7%,” NYISO CFO Cheryl Hussey told stakeholders. “The projected 2025 megawatt-hour throughput is an increase of 2.6 million MWh, which is an increase of 1.7% compared to 2024.” 

Hussey reported that NYISO is projecting a 2024 budget surplus because of overcollections under RS1 and spending being under budget. The ISO is therefore proposing an RS1 carryover of $3 million into the 2025 budget. This would reduce the impact of 2025 cost increases by approximately 2 cents/MWh, Hussey said. She also explained that if the carryover were not used to decrease the cost of RS1, it would be used to pay down debt. 

“For example, in 2023, we used $5 million as a carryover, and then the balance we used to pay down debt,” Hussey said. “In recent years, we’ve used a surplus to pay down debt. 2023 was the first time in a number of years that we proposed a carryover.” 

Debt servicing was projected to increase in 2025 to $7 million, an increase of about $4.8 million. 

Mark Younger, of Hudson Energy Economics, requested that NYISO provide more information about the kinds of debt the ISO had currently so stakeholders could see whether paying off high-interest and variable-interest loans or a carryover would be a better use of funds. Hussey said NYISO might be able to present something to address that at future meetings. 

“Why are your debt services going up?” asked Amanda De Vito Trinsey of Couch White, representing New York City. 

Hussey explained that in 2024 and 2025, NYISO was borrowing more money to pay for its increased project portfolio and infrastructure capital needs. In 2024, the ISO had borrowed $37 million to pay for its projects. 

“Obviously, the more money we borrow, we need to pay that back, and that leads to increased debt service costs in future years,” Hussey said. “I’ll point out that we are proposing to borrow $37 million again in 2025 to cover the cost of the project portfolio.” 

Hussey ran through more drivers of the cost increase, including a cost-of-living adjustment for its Market Monitoring Unit. Salary and benefits are also increasing between 4 and 6%, with 19 new staff positions being added, primarily to work on FERC orders 2023 and 1920 compliance and the Coordinated Grid Planning Process. 

“We always have to keep in mind that we maintain our salaries as competitive as compared to the market and as best we can limit inequities between certain positions that we have here at the ISO that should be placed in similar levels,” Hussey said. 

One stakeholder asked whether the budget was based on full staffing or the expected vacancy rate for NYISO. Hussey said that the vacancy rate was expected to be around 6% and that the budget was based on that lower number. She explained that NYISO was balancing its staffing needs against normal churn and imperfect replacement of departing employees. 

The final big line item was computer services. NYISO projects it will spend $3.9 million on computer services, up $1.5 million from the previous year. This is primarily for upgrades, enterprise software subscription costs and increased Amazon Web Services costs. 

Forecasts Through 2029

Max Schuler, an economic analyst for NYISO, presented the RS1 forecast through 2029. 

The RS1 rate is based on net load, billable exports, wheel-throughs and incremental supply. NYISO anticipates increased load driven by large load interconnections, electric vehicles, heating electrification and general economic growth.  

“Another important factor is the weather, which is most significant during the winter months for the exports and general system conditions and balance with external control areas,” said Schuler, while also noting that climate change is expected to lead to increased net load because of warmer weather in the summer.  

Schuler said that by 2029, the total throughput is expected to reach 159,400 GWh. Balancing the expected increases in net load are increased behind-the-meter solar, energy efficiency and billable exports. BTM solar and EE are forecasted to cut RS1 by 0.6 and 1.3%/year, respectively.  

Net load is forecasted to dip slightly in 2025 to 147,850 GWh from this year’s estimate of 148,580 GWh. After next year, NYISO thinks that the net load will gradually increase to 152,320 GWh by 2029. 

Next Steps

The Board of Directors will review a “high-level” summary of the draft budget at its meeting Sept. 17, with the Management Committee reviewing it at its meeting Sept. 25. 

Following more Budget and Priorities Working Group meetings, the MC is expected to vote on the budget Oct. 31 and the board Nov. 19. 

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Consumer Response Saved Alberta Grid During Jan. 2024 Cold Snap

An emergency alert urging the public to conserve energy helped the Alberta Electric System Operator narrowly avert rolling blackouts during January’s extreme cold snap, an AESO representative said during a WECC webinar.

The Alberta Emergency Management Agency sent the alert to cell phones and televisions at 6:44 p.m. on Saturday, Jan. 13, asking residents to immediately limit their electricity use to essential needs only.

“Extreme cold resulting in high power demand has placed the Alberta grid at a high risk of rotating power outages this evening,” the message said.

Within three minutes, load dropped by 170 MW, followed by an additional 100 MW after 10 minutes, according to Lane Belsher, AESO’s director of grid and market operations. Load continued to fall as “people were shaming their neighbors into shutting their lights off,” he said.

“It amazed me,” Belsher said. “We did not end up shedding any firm load.”

Belsher discussed the January cold snap during a Sept. 10 WECC webinar focused on winter-weather readiness.

The Canadian province had been enjoying mild, fall-like weather in early January before temperatures dropped below minus 40 degrees Fahrenheit in some locations.

The system hit an all-time winter peak of 12,384 MW on Jan. 11. Strong winds — and accompanying wind generation — that accompanied the falling temperatures helped the system meet demand on that day, Belsher said.

But conditions grew more challenging as the wind died down. AESO issued an energy emergency alert 3 on four days in a row, from Jan. 12-15.

The situation was especially dire as AESO neared its peak demand Jan. 13. Solar power is mostly gone by the peak, Belsher said, and AESO is heavily dependent on gas generation during winter.

But right at the system peak, generation from a large thermal unit dropped from 450 MW to about 160 MW, he said. AESO decided to use 190 MW of battery storage that it had been keeping “in our back pocket,” Belsher said. But the extreme temperatures meant the batteries would work for only about an hour rather than the expected two hours.

Similarly, about 150 MW was available through Western Power Pool reserve sharing, but only for about an hour.

Belsher talked to Alberta government officials, who deemed the situation to be life-threatening. The emergency alert was sent to the public, and blackouts were avoided.

Alert Used During Calif. Heat Wave

A public alert is a tool that has also been used successfully to avoid rolling blackouts in California — albeit during a heat wave rather than a cold snap.

At 5:45 p.m. on Sept. 6, 2022, the Governor’s Office of Emergency Services sent a message to 27 million cell phones, accompanied by a series of shrieking tones.

The message, sent during a 10-day, record-breaking heat wave, said: “Conserve energy now to protect public health and safety. Extreme heat is straining the state energy grid. Power interruptions may occur unless you take action.”

CAISO saw demand drop by 2,385 MW, to 48 GW, within 20 minutes of the alert, enough to avoid blackouts. (See CAISO Reports on Summer Heat Wave Performance.)

At AESO, another issue during the January cold snap was the price cap for imports. Belsher said the Mid-C spot price in the Northwest the evening of Jan. 13 was about $1,300 CAD; AESO’s price cap is $1,000.

Belsher noted that the system completed its phaseout of coal this year. A gas generator was off temporarily during the cold snap due to a frozen gas valve.

Two additional combined-cycle gas units were commissioned this year but weren’t available in January.

“It would have been nice to have them, but I think we’re in better shape for this winter coming forward,” Belsher said.

Another speaker during the WECC webinar was David Lemmons, co-founder of Greybeard Compliance Services. He discussed a new NERC standard, EOP-012-2, which requires power plants to have a winter-readiness plan.

Lemmons said plant operators should consider whether their gas delivery path is protected from the weather, and if start-up will take longer when it’s cold outside.

Other advice included checking for broken or missing windows and making sure windows are closed before cold weather arrives.

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Clean Energy Buyers Push Passage of New Calif. Reliability Law

Large buyers of clean energy were the key backers of a California bill passed last month to strengthen the state’s reliability planning.

The state’s reliability planning has grown more challenging given the increased frequency of extreme weather events, higher temperatures and greater load variability — creating the need for better planning to offset uncertainty and keep the lights on.

Sponsored by the Clean Energy Buyers Association (CEBA), Assembly Bill 2368 seeks to address that need, requiring the California Public Utilities Commission to adopt a 1-in-10 loss of load expectation (LOLE) — or a similarly robust planning standard — when setting resource adequacy requirements.

The bill also directs the commission to develop a “mid-term reliability assessment” using probabilistic modeling that looks two to five years into the future to better anticipate potential procurement shortfalls and resulting reliability issues.

Additionally, it requires increased information-sharing between the CPUC and CAISO to enable the ISO to conduct its own reliability modeling and ensure it can meet its own regulatory obligations.

While the 1-in-10 metric is a widely used planning standard, the legislation marks the first time it has been written into California law.

According to Heidi Ratz, CEBA deputy director of market and policy innovation, FERC views RA as state jurisdictional, though most planning standards are set by regional balancing authorities. Other entities, such as the Western Resource Adequacy Program, have formalized a 1-in-10 LOLE target, and agencies such as the CPUC and the California Energy Commission support it for California.

‘Right Amount of Resources’

Proponents of the bill say that enshrining a stricter LOLE standard into law will modernize the state’s planning framework and improve the planning and procurement process.

“Grid planners in California have acknowledged the challenges to electricity resource adequacy and grid reliability within the state, and CEBA sponsored this legislation to tackle some fundamental energy planning issues,” Ratz said in a CEBA press release. “As our grid faces unprecedented pressures, including extreme weather and demand growth, California leaders must have a sense of urgency in implementing sound resource adequacy planning and procurement processes.”

Ratz further emphasized that the bill will help grid planners increase trust in their RA programs and decrease the need to rely on the state’s Strategic Reliability Reserve.

“As planning agencies move towards procuring the right amount of resources well in advance, we will see fewer outages, ‘near misses’ and emergency procurements, meaning reliability will hopefully be noticeably improved,” Ratz told RTO Insider in an email. “We’ll also see a decrease in scarcity which leads to lower transaction costs in the real-time energy market and more functional capacity markets that send better price signals to market participants. Ensuring the right resources show up in the energy market during times of grid stress is the primary way to improve reliability.”

CAISO stakeholders have been calling for improved LOLE modeling for some time. In June, Gridwell Consulting asked the ISO to take a bigger role in reliability planning and conduct probabilistic LOLE modeling to better understand the aggregate impact of the changing climate on grid conditions. (See Stakeholders Call on CAISO to Take Larger Role in Reliability Planning.)

Gridwell CEO Carrie Bentley emphasized the need for better planning by citing data showing that, between 2017 and 2023, load variability was significant enough to cause load forecasts to deviate from actual loads by several thousand more megawatts than historically normal.

Gridwell joined CEBA in support of the legislation, also emphasizing its potential to lower costs.

“This will improve reliability and in the long run lower costs compared to the system in place today that caused California’s reliability levels to vary widely over time,” Bentley said.

In 2014, the CPUC opened a proceeding to address mid-term reliability that resulted in recommendations that were never adopted. Had they been adopted, it is likely that much of 2020’s capacity shortfalls could have been avoided, Ratz said. The lack of a stricter planning and modeling framework created the conditions for the events in 2020 and continues to have impacts on cost and reliability.

“Since the outages of 2020, California has issued four last-minute, ad-hoc emergency procurement orders; each ordered the LSEs to sign contracts with new resources that can come online as quickly as possible,” Ratz said. “CPUC did conduct limited modeling (reliability analyses) before adopting these decisions that demonstrated the urgent need for additional generation capacity to come online in the mid-term. Combined with the strategic reserve, these were some of the most expensive procurements in California’s history, and these expensive electricity emergencies have material impact on customers’ operations in the state.”

CEBA is urging Gov. Gavin Newsom to expedite signing the bill, which has received support from other agencies such as the Environmental Defense Fund, Pacific Gas and Electric, International Brotherhood of Electrical Workers and more.

AB 2368 is the first reliability-focused bill sponsored by CEBA, signaling the importance of reliability to the group’s members.

“The planning improvements in the bill are critical to California’s ability to provide energy customers with low-cost, reliable, clean power,” Ratz said.

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FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate

FERC has dismissed separate complaints from MISO and Montana-Dakota Utilities Co. over a MISO-SPP flowgate chronically stressed by a North Dakota cryptocurrency mining operation.   

The commission issued a Sept. 10 order, refusing the pair of complaints; it said neither MISO nor Montana-Dakota Utilities (MDU) proved that the Charlie Creek flowgate in North Dakota failed to meet the criteria for market-to-market (M2M) coordination, nor was SPP in the wrong for continuing to insist on M2M coordination (EL24-61).  

MISO and MDU have been sparring with SPP over the flowgate since last year, when cryptomining facility Atlas Power Data Center opened and brought 200-MW load to SPP’s transmission-constrained Northwest North Dakota load pocket, which now has a peak load of about 1.5 GW but only approximately 1 GW of import capability. (See MISO Lodges 2nd Complaint Against SPP over Disputed Crypto Load on M2M Flowgate.)  

FERC said it disagreed with MISO and MDU that SPP violated sections of the MISO-SPP joint operating agreement, that MDU incurred duplicate congestion charges and that the rules MISO and SPP rely on for M2M termination are unreasonable.  

The commission found that “MDU and MISO have not demonstrated that SPP acted unreasonably in declining to grant consent to remove the Charlie Creek Flowgate from the market-to-market coordination process.”  

SPP has maintained that Charlie Creek remains eligible for M2M coordination based on the RTOs’ flowgate studies, which it argued determine hundreds of other MISO-SPP flowgate designations. 

MISO and MDU have argued that although the Charlie Creek Flowgate passes MISO and SPP’s flowgate studies, its M2M status should be revoked because the RTOs’ coordination is helping SPP manage a local issue caused by data center load growth, and not a regional issue. The two said the congesting spikes caused by the Atlas Power Data Center are squarely in SPP’s territory and said SPP’s insistence on M2M coordination is at the detriment of MISO market participants and customers.  

MISO last year initiated a formal dispute process with SPP over the flowgate. By March, it asked FERC to terminate M2M coordination on Charlie Creek and requested refunds on the M2M coordination charges it paid to SPP beginning in April 2023.  

MDU filed a complaint against MISO and SPP early this year, saying it was overcharged $18 million for congestion management because the two RTOs were conducting unwarranted M2M coordination. MDU, a MISO member, has 150 MW of load and two 115-kV lines in the load pocket and relies on network integration transmission service from SPP to serve load when its own transmission is insufficient. 

MISO claimed that improper M2M coordination cost its members $38 million in M2M charges to manage congestion. The grid operator also argued that SPP’s approval of a temporary remedial action scheme for the Charlie Creek flowgate shows that the M2M coordination is being used to address a local issue wrought by load growth.   

MISO’s Independent Market Monitor further argued that, during periods of market-to-market coordination, MISO could provide less than 1 MW of relief on the Charlie Creek flowgate, while curtailment of Atlas’ load in SPP could provide more than 90 MW of relief. 

However, FERC said MISO and MDU were misreading the definition of an M2M flowgate as laid out in the MISO-SPP joint operating agreement. FERC said while a section of the RTOs’ Interregional Coordination Process says M2M coordination should be reserved for issues that are regional and not local in nature, that’s not an explicit prerequisite for a flowgate to be eligible for an M2M flowgate designation. 

Because it determined the regional issue threshold wasn’t a requirement for M2M coordination, the commission declined to determine whether the added cryptomining load constitutes a local issue. 

FERC pointed out that SPP provided evidence that revoking Charlie Creek’s M2M flowgate status might risk SPP needing to resort to transmission loading relief or load shedding.  

FERC also refused to deem MISO and SPP’s Interregional Coordination Process unreasonable because it allows either MISO or SPP to refuse to lift M2M designation even when the other RTO can offer little congestion relief. MISO argued that the mutual agreement condition amounted to an “unconditional veto.”  

But the commission said the rules give MISO and SPP “reasonable discretion on an equal basis to mutually agree to add or remove market-to-market flowgates without any conditions or requirements.”  

FERC decided SPP acted reasonably by not agreeing to remove M2M coordination. It said SPP provided evidence that it can redispatch to alleviate the flowgate in “most” hours. FERC also said keeping up the M2M coordination “helps create an appropriate market signal for MISO to dispatch generating units within its footprint that have a significant generator shift factor on the flowgate,” making for a more efficient market solution versus terminating M2M procedures.  

Because it denied the complaints, FERC likewise denied a related waiver request from MISO that would have allowed the RTO to adjust SPP’s Integrated Marketplace settlements beyond the current 365-day limit (ER24-1586).  

Nearby Basin Electric Power Cooperative announced plans in May to build a 1.4-GW gas-fired power plant to address growing demand from North Dakota’s data center industry.  

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ISO-NE Responds to Feedback on Capacity Auction Reforms Scope

ISO-NE’s Capacity Auction Reforms (CAR) project will include an evaluation of additional resource accreditation modeling enhancements, the RTO told the NEPOOL Markets Committee on Sept. 10. 

The RTO also plans to estimate seasonal tie benefits in its resource adequacy assessment model, it said. The remarks came in response to feedback it solicited on the “straw scope” of the project, which aims to move the Forward Capacity Market to a prompt and seasonal market. (See ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms.) 

Some stakeholders argued  ISO-NE’s resource accreditation modeling does not accurately reflect the region’s risk profile, including the duration of events. (See ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.) 

“As part of CAR, the ISO plans to assess whether it can make further enhancements to the modeling and accreditation proposal to better align accreditation values with contributions to resource adequacy,” said Chris Geissler, ISO-NE director of economic analysis. The RTO also plans to consider how it models intermittent and limited-energy resources, along with improvements to the load model, he said. 

Other stakeholders expressed concerns  the new accreditation methodology would not consider the marginal reliability impact (MRI) of tie benefits, potentially causing the RTO to overestimate the reliability benefits of interties. 

In comments submitted prior to the meeting, Calpine argued that “any supply source, including imports, used to meet capacity requirements should be counted similarly and subject to similar performance requirements” and that ISO-NE “should apply this standard to the CAR work.” 

Geissler said the RTO will work with its neighbors to evaluate seasonal tie benefits, which “represent the expected contribution from other regions during emergency conditions.” 

However, ISO-NE does not plan to calculate MRI values for tie benefits, or to subject tie benefits to Pay-for-Performance (PFP) rules, Geissler said. He noted that tie benefits will be modeled in resource adequacy assessments, which are used to determine the RTO’s installed capacity requirement. He added that “tie benefits are not directly competing” with capacity resources to meet this requirement. 

Geissler also told the MC that ISO-NE is not planning to include an evaluation of how the capacity market treats resource retentions. He added that, in a future phase of work, the RTO may consider broader changes to its rules for reliability-must-run contracts if it determines that retentions for energy security reasons are needed. 

The RTO also is not planning to model resource start times because of the constraints of GE MARS, its resource adequacy modeling software, despite interest from some stakeholder groups, Geissler said. 

“Assessing changes to the resource adequacy platform would be a significant, multiyear effort that would take resources away from other parts of the CAR effort and jeopardize the ISO’s ability to complete CAR in time for [capacity commitment period] 19,” Geissler said. 

In a memo published prior to the meeting, environmental advocacy groups pushed the RTO to model startup times, arguing it is a necessary step to fairly compensate resources for their ability to support the power system on short notice. 

“Units with lengthy startup times simply do not offer the same resource adequacy value as more flexible ones,” the organizations wrote. “We understand that this will involve substantial resources, but given that ISO has already committed to spending several years on overhauling its capacity market reform, now is the best time to address this important consideration.” 

The groups also urged the RTO to model “correlated outages and ambient temperature adjustments” as part of the CAR project. 

Gas and diesel resources are “susceptible to both cold and hot temperature-dependent forced outages,” the organizations said while calling on ISO-NE to “model these reliability impacts as accurately as possible.” 

Geissler said ISO-NE still is considering whether to include temperature adjustments and correlated outages in the project scope, noting that the topic “raises technical modeling questions that must be more fully assessed before a decision can be made.” 

He added that ISO-NE is planning to model correlated outages of gas resources related to the region’s gas constraints in the winter. 

IMM Quarterly Markets Report

Wholesale market energy costs were down by 23% this spring relative to that of 2023 because of lower natural gas prices and capacity clearing costs, according to the ISO-NE Internal Market Monitor’s quarterly markets report. 

The real-time hub LMP averaged $24.64/MWh, ranging from 9 to 13% lower than in spring 2023. The average load (11,869 MW) was up by about 180 MW per hour in part from higher temperatures in May compared to the prior year. 

Nuclear generation rebounded after several down seasons because of lower rates and accounted for about 28% of the average output. Natural gas remained the largest generation source at 45% of the average output. Imports decreased because of a drought in Canada that affected hydro reservoir levels. 

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BLM OKs NV Energy’s Greenlink West Line

The U.S. Bureau of Land Management on Sept. 9 issued a record of decision approving NV Energy’s Greenlink West, a 470-mile transmission line that will connect Las Vegas with the northern part of Nevada and be capable of transmitting up to 4,000 MW of energy.

The project will consist of a 350-mile, 525-kV segment from Las Vegas to Yerington, along with two 345-kV lines running from Yerington into the Reno/Sparks area. Construction of the line is expected to begin in the first quarter of 2025 with an in-service date targeted for May 2027.

BLM also opened a comment period for a proposed draft resource management plan amendment and environmental impact statement for the Greenlink North project, a 210-mile east-west line designed to connect Greenlink West with NV Energy’s existing One Nevada Line running along the eastern part of the state.

NV Energy considers the Greenlink projects to be “vital” to tapping the state’s renewable resources and maintaining grid reliability in the face of growing load, an NV Energy executive said in the utility’s most recent integrated resource plan, filed with the Public Utilities Commission of Nevada in May.

But the IRP also revealed the rising costs for the projects, now estimated at $4.239 billion, a 70.6% increase from initial estimates made in 2020. NV Energy attributed $124 million of the increase to the BLM’s requirement that the utility use an additional 160 miles of H-frame structures to mitigate risk to desert tortoise and sage grouse habitat. Other environmental mitigations added $30 million to project costs. (See NV Energy IRP Describes $1.76B Cost Jump for Greenlink Projects.)

Given Nevada’s central position between the resource-rich interior West and more populous West Coast, the Greenlink project also likely will play a key role in transferring energy among various regions participating in CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM). In May, NV Energy said it would choose to join EDAM over SPP’s Markets+, a major victory for CAISO in the competition between the two Western day-ahead markets. (See NV Energy Confirms Intent to Join CAISO’s EDAM.)

Massive Solar-plus-battery Project Approved

The BLM on Sept. 9 also approved Arevia Power’s $2.3 billion Libra Solar Project, which will be built across 5,778 acres of public land in Mineral County, Nevada. It will be one of the largest solar-plus-battery storage projects in the U.S., consisting of 700 MW of solar and 700 MW/2.8 GWh of energy storage capacity. NV Energy will be the off-taker for the project’s output.

“From building large scale transmission lines to solar power generating facilities, the Interior Department and our team at the Bureau of Land Management are leading the way in the development of reliable, clean energy across the West,” acting Deputy Secretary of the Interior Laura Daniel-Davis said during a Sept. 10 event in Las Vegas to announce the developments. “The infrastructure projects we are advancing today in Nevada are helping meet President Biden’s ambitious renewable energy goals while making communities more energy resilient and creating good-paying jobs in the clean energy economy.”

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NY OSW: If at First You Don’t Succeed, Try, Try Again

Two of the offshore wind developers that won and then lost contingent New York contracts are trying again, submitting proposals into the state’s latest solicitation. 

Community Offshore Wind and Excelsior Wind could be the fourth and fifth wind farms off the coast of New York, which is pursuing development of an offshore wind sector vigorously but with mixed results. 

Community and Excelsior announced their proposals Sept. 9, the final day to submit proposals without price tags in New York’s fifth competitive offshore wind solicitation (NY5). 

The New York State Energy Research and Development Authority (NYSERDA) would not say how many other proposals it received. It said redacted versions of the proposals would be made public in coming weeks.  

The process is not complete — developers must submit price tags for their proposals by Oct. 18 — but the door now is closed to additional proposals into NY5. 

NYSERDA expects to make contingent awards by Nov. 8, then execute the contracts and announce them to the public in the first quarter of 2025. 

Community is proposed by RWE and National Grid Ventures. Excelsior is proposed by Vineyard Offshore, an affiliate of Copenhagen Infrastructure Partners. 

In October 2023, Community and Excelsior were awarded contingent contracts in NY3, along with Attentive Energy One. All three contracts were predicated on an 18-MW turbine under development by General Electric.  

When the company — now GE Vernova — halted development of that machine, the contracts no longer penciled out. The NY3 solicitation was canceled, and the conditional contracts for 4 GW of capacity from the three projects were canceled in April 2024. (See NY Offshore Wind Plans Implode Again.) 

Excelsior announced Sept. 9 it had submitted a 1,350-MW project in NY5 — nearly the same nameplate capacity it had proposed in NY3. Community did not specify the nameplate capacity of the wind farm it is proposing for NY5. 

Headwinds

New York’s experiences are among the best examples of the growing pains of the U.S. offshore wind industry as it takes root off the Northeast coast. It has not had a project cancellation, like New Jersey has, but it has gone through multiple gyrations.  

New York has the first and so far only completed utility-scale offshore wind farm in U.S. waters, the 132-MW South Fork Wind. It also has Sunrise Wind and Empire Wind 1 under contract, and Sunrise is in early stages of construction. 

Along with the three contracts lost to supply chain problems in NY3, New York saw cancellations of contracts for Beacon Wind, Empire Wind 2 and earlier contracts for Empire 1 and Sunrise when soaring costs made those contracts untenable. The second contracts for Sunrise and Empire 1 carry much higher costs for ratepayers. 

Community is persistent if nothing else. 

It nearly won then lost the NY3 contract. It submitted a proposal into NY4 but was “waitlisted” and then not chosen. It submitted a proposal into NJ3, then withdrew it after concluding the pricing did not work. It submitted a proposal into NJ4 that is awaiting a decision by the state. 

(Community’s lease area is large enough and close enough that it could feed the grid in both New York and New Jersey.) 

The drive continues, and new headwinds arise even as previous problems are resolved. 

Atlantic Shores Offshore Wind this summer rebid into NJ4 a wind farm already under contract in New Jersey, presumably at higher cost. (See 3 OSW Proposals Submitted to NJ.) 

In recent weeks, Leading Light Wind has asked the New Jersey Board of Public Utilities for a delay because it is having trouble securing a supply contract for turbines. 

Earlier this month, the first-ever multistate solicitation was a decidedly mixed bag: Connecticut, Massachusetts and Rhode Island sought up to 6 GW of combined capacity and received 5.45 GW of proposals. But the projects selected totaled only 2.88 GW — 2.68 GW for Massachusetts, 0.2 GW for Rhode Island and 0.0 for Connecticut, which said it was still evaluating bids. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) 

Vineyard Offshore proposed the 1.2-GW Vineyard Wind 2, up to 800 MW of which was selected by Massachusetts. The developer implied its ability to move forward with the project depended on Connecticut signing up for the rest.  

“We look forward to Connecticut’s forthcoming decision on the remainder of the procurement so that we can begin to deliver important economic and climate benefits to the region,” CEO Alicia Barton said in a news release. 

In the background to all this, a turbine blade disintegrated at Vineyard Wind 1 in July, littering beaches and waves with fragments and giving offshore wind opponents a camera-ready moment they are exploiting two months later. (See Blade Failure Brings Vineyard Wind 1 to Halt.) 

On a positive note, the first turbine recently was hoisted into position off the New England coast for Revolution Wind, which is expected one day to send up to 700 MW to Connecticut and Rhode Island.  

But Revolution, too, has had its setbacks. Brownfield contamination where its onshore substation will stand has pushed the anticipated completion date back from 2025 to 2026. (See Revolution, Sunrise OSW Projects Face New Delays.) 

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Potential Seen to Add up to 95 GW to US Nuclear Plants

The U.S. Department of Energy estimates that existing and recently retired nuclear power sites could host an additional 60 GW to 95 GW of new nuclear generation. 

DOE also said an additional 128 GW to 174 GW of new nuclear capacity could be built near existing or recently retired coal-fired facilities. 

In its 2023 report “Pathways to Commercial Liftoff: Advanced Nuclear,” the department estimated the U.S. would need 200 GW of additional nuclear capacity by 2050 to meet the growing demand for electricity and the growing emphasis on emissions-free generation. 

“A good chunk of that could come from a familiar place,” Michael Goff, acting assistant secretary for the U.S. Department of Energy’s Office of Nuclear Energy, wrote Sept. 9 in introducing the new report. 

“Evaluation of Nuclear Power Plant and Coal Power Plant Sites for New Nuclear Capacity” finds that 41 operating and retired nuclear sites could accommodate one or more new large light-water reactors rated at 1,117 MW for a total of 60 GW of new capacity. 

Using advanced reactors rated at 600 MW would bring the total to 95 GW, as more reactors could be built on more sites. 

For its analysis, DOE examined 54 operating and 11 recently retired nuclear power plant sites in 31 states.  

To determine suitability for expansion, it examined site footprint and acreage, aerial analyses, utility plans, a siting analysis tool developed by Oak Ridge National Laboratory, availability of cooling water, proximity to population centers or hazardous facilities, seismic risk and flood hazards. Researchers from Oak Ridge and Argonne National Laboratory contributed. 

Important tangible considerations such as politics and finances were not on the list of factors considered, though Goff acknowledged that capital costs will be a key factor in decisions about nuclear plant construction. 

He cited a study showing the majority of people who live near nuclear power plants consider them good neighbors. And there is hope that a concerted buildout of new nuclear plants will create economies of scale that limit the cost of new nuclear construction, which has seen exorbitant cost overruns. 

For coal-burning plants, which are being retired or scheduled for retirement at a steady rate, the study looked only at sites with a nameplate capacity of at least 600 MW that are active or were retired after 2019. It assumed retired plants had not been converted to natural gas and that their licenses to provide power to the grid were still in effect. 

Replacing coal with nuclear in a timely fashion could benefit the surrounding communities economically and environmentally and take advantage of existing workforces. A 2022 DOE report delved further into the opportunities and challenges that would surround such conversions. 

Goff stressed that this new analysis is preliminary. “Utilities and communities will need to work closely together to make the decisions on whether to build a new plant,” he wrote. 

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MISO, SPP Try Again to Find Joint Seam Projects

After five fruitless attempts to agree on joint transmission projects across their seams, MISO and SPP will use what they call a “blended joint model” in parallel with existing SPP and MISO regional models.

The RTOs’ staffers told stakeholders during a Sept. 9 Interregional Planning Stakeholder Advisory Committee meeting that their Coordinated System Plan (CSP) study, required every two years by a joint operating agreement, will identify near-term upgrades that “incrementally enhance” transfer capability and produce multiple benefits across the two grids. The study will include reliability, economic and transfer analysis using forward-looking models and assumptions (10- and/or 20-year models), they said.

“The hope is that we have some mutually beneficial projects that we can both agree to recommend approval and ultimately share costs and construct,” SPP’s Clint Savoy said. “That’s the way the current process works today, or that’s the way it’s envisioned in the JOA.”

Five previous studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue project, which identified a $1.86 billion portfolio of five projects that could support up to 28 GW of interconnecting generation on both sides of the seam. The Department of Energy last year awarded the portfolio $464 million under its Grid Resilience and Innovation Partnerships program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

Under the blended model, MISO will use its 2023 Long-Range Transmission Planning reliability and economic model sets and SPP will run the 2025 Integrated Transmission Planning’s same model sets. Staff will use three of four base seasonal models (winter peak, summer peak, average load and light load).

The RTOs both want a multi-benefit style project type and cost allocation to draw on a broader set of benefits for project recommendations, they said. Savoy said FERC Order 1920, which requires transmission-planning regions use at least a 20-year horizon, has provided something of a guidepost for the RTOs to follow.

“We hope this new approach will let us look into additional drivers for projects other than just economic or reliability benefits, if you will, maybe consider different assumptions as we are developing, the list of needs that we want to fix,” he said. “And so what we hope is a better outcome to look more proactively, maybe have a broader set of issues that we’re looking for or benefits to consider, rather than just the traditional economic reliability and public policy.”

The two staffs will continue to develop the study’s scope, incorporating stakeholder feedback, and share it with stakeholders when complete later this year. The 2024 CSP will run through 2025.

The RTOs will have to file a waiver request with FERC requesting permission to use the blended study process. They said they will partner with states and stakeholders to identify and file any needed changes to their JOA and tariffs.

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Webinar Examines How FERC Could Use Interregional Transmission Study

Congress and FERC will need to act to update the rules on interregional transmission planning, and likely permitting, if NERC’s Interregional Transfer Capability Study is going to be of any use, experts said on a webinar hosted by Americans for a Clean Energy Grid.

The study is only the second thing Congress has ever requested from NERC, after it called for the creation of the Electric Reliability Organization in the Energy Policy Act of 2005, said John Moura, director of reliability assessment and system analysis. NERC recently released its initial results, but the final report is not due to FERC until Dec. 2. (See NERC Examines Transfer Capability in Draft ITCS Installment.)

“The ITCS is really an unprecedented study, both in scale and magnitude of what we have to look at,” Moura said. “It’s a U.S.- and Canada-wide technical assessment that looks at the power transfers between regions, and then also makes recommendations to increase those transfers based on reliability needs.”

Once FERC gets the report in December, it will open it up for comments, which will put it before a much larger group of stakeholders, Moura said. Though Congress directed the study, Canadian representatives wanted their own version, which will be published in the first quarter of 2025, he added.

NERC found greater needs for transfer capabilities in some regions compared to others, with Moura presenting a color-coded slide with green, yellow and red for increasing regional needs. While the red and orange areas would benefit from more transfer capacity, Moura noted that the green and gray regions still require work to maintain reliability.

The study assigned “prudent” transfer capability between regions, which means how much is required to meet load under extreme conditions, Moura said.

In doing the study, NERC had to use the same metrics for different regions, which is not how it operates in its own regional planning efforts, so it could accurately assess transfer capabilities. One key finding of the studies is that increasing interregional transfer capability is not enough to ensure reliability.

“I think the results are pretty clear: Adding transfer capability to a minimum level is not sufficient in resolving reliability issues for some areas,” Moura said. “And for other areas, adding transfer capability where it’s not needed would not appear to be economically prudent, without much benefit to reliability. Also, transmission is only one option and only one solution.”

Transfer capability can help with reliability issues in some regions, but so can adding new generation — especially types that are not subject to the same common mode failures plaguing generator availability, Moura said. Higher transfer capabilities will require significant planning and systemwide reinforcements, he added.

Nicole Luckey, Invenergy senior vice president of regulatory affairs, said the current rules are not working.

“There are no holistic interregional transmission planning or cost allocation processes in place today, aside from what was laid out in Order 1000, which I think we all can acknowledge isn’t necessarily working now,” Luckey said. “We’re all really looking forward to the folks in the transmission development community seeing what FERC does with NERC’s study.”

One question is whether the commission will stick to purely reliability benefits or consider others in that effort, she added.

American Electric Power owns utilities in four different ISOs and RTOs, and many of its territories are located along market seams, so it has had a front-row seat to view how Order 1000’s interregional process has failed, said Stacey Burbure, vice president for FERC and RTO strategy. A key reason is that different regions consider transmission with different metrics.

“When you’re comparing apples and oranges, it’s not always intuitive what the right solution is, which is why coordination simply hasn’t gotten us there,” Burbure said. “The RTOs are on different timelines. They’re looking at different inputs. So, moving towards a more standardized approach, with respect to that engineering information, is going to be critical in order to get the right transmission built.”

FERC should take steps with interregional transmission like it did in Order 1920 with regional planning, so the different regions are examining interregional lines on the same basis, she added.

Brattle Group Manager Joe DeLosa agreed that FERC would need to get more common metrics in place to make interregional planning successful, but he also noted that planners currently use models of the system in normal conditions.

The National Renewable Energy Laboratory “has recently said that about half of the benefits of interregional transmission come from the most stressed 5% of system hours,” DeLosa said. “And so, if your interregional coordination/planning, especially for economics, doesn’t take a look at those hours, you’re going to be overlooking large portion of potential interregional benefits, and you’re not ultimately going to develop the appropriate projects.”