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November 17, 2024

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PJM PC/TEAC Briefs: Sept. 12-13, 2024

VALLEY FORGE, Pa. — The PJM Planning Committee and Transmission Expansion Advisory Committee meetings were originally scheduled for Sept. 10 but were rescheduled to Sept. 12 and 13, respectively. 

Planning Committee

Voting on CIR Transfer Proposals Deferred to October

The PC on Sept. 12 voted to defer action on three proposals to rework the RTO’s process for transferring capacity interconnection rights (CIRs) from a deactivating generator to a new resource. The committee will vote on them at its next meeting, currently scheduled for Oct. 8. 

Each of the packages is aimed at creating an expedited process to shift the transmission capability underlying the CIRs of a retiring unit to support the interconnection of a new resource. Proponents of the concept say it could alleviate the need for costly reliability-must-run (RMR) contracts to keep resources online while upgrades are made to the grid to pre-empt any transmission violations prompted by removing a generator. 

The vote was delayed after the committee rejected an amendment to a proposal sponsored by Elevate Renewable Energy and the East Kentucky Power Cooperative. (See “Elevate Reviews CIR Transfer Proposal,” PJM PC/TEAC Briefs: July 9, 2024.) 

The amendment, proposed by MN8 Energy, would have added thermal violation analysis to the studies to be conducted on projects seeking CIR transfers and expedited interconnection. MN8 had withdrawn its own package ahead of the meeting and thrown its support behind the Elevate-EKPC coalition. 

The MN8 amendment would have required thermal studies on the peak and off-peak deliverability cases, but Elevate’s Tonja Wicks said the coalition could only accept studies on the off-peak case. 

The issue of thermal studies gets to the heart of whether storage resources should be eligible for CIR transfers, with PJM arguing that the capability to charge off the grid could pose “material adverse impacts” not envisioned by the original interconnection studies conducted on the deactivating generator. The PJM proposal would outright disqualify storage and open-loop hybrids, whereas both the coalition and Independent Market Monitor packages would allow all resource classes to participate. 

Coalition supporters argued storage is one of the best-suited resources for replacing deactivations owing to its quick installation time, minimal footprint and minimal environmental restrictions. Alternatives like renewable generation can require too much land to be viable for replacements in urban settings, such as the retiring Brandon Shores generator outside Baltimore, and the timeline for new nuclear is too lengthy to be suitable, they said. 

The material adverse impact standard would also preclude many CIR transfers to resources with a different fuel type, PJM’s Ed Franks said. Any projects requiring network upgrades would be removed from the expedited process and moved to the general interconnection queue. 

Both the PJM and coalition proposals would only allow CIR transfers to resources seeking to site at the same point of interconnection (POI) as the deactivating unit. The voltage would also be required to be the same, though the interconnection could be at a different breaker. 

The coalition proposal comes with a nine-month time frame for most projects to get through the expedited process, with 60 days for initial application review, 180 days for a replacement impact study looking at any potential transmission violations and 30 days for the interconnection service agreement to be approved. Projects with minor network upgrades required would take an additional 90 days. 

It would also allow the transfer process to begin before an official deactivation notice has been filed with PJM, allowing discussions between market participants and the RTO’s study process to begin quicker. PJM’s proposal would require an official notice before CIRs transfers could be initiated. 

Interconnection studies on expedited projects would be conducted in parallel with Phase 2 studies being conducted on the contemporaneous cluster in the transitional cycle. PJM’s proposal would also place expedited studies at the second phase of the current cluster. 

Franks said moving new CIR transfer requests up to be studied with the current cluster is one of the defining features of the packages. While the status quo does allow transfers, only submissions made before the start of the transition to the cluster-based process were sorted into either Transitional Cycle 1 or 2. Later requests must wait until the end of the transitional cycle to be studied as part of TC 1, which is not scheduled to begin reviewing applications until 2026. Franks said the proposals would also result in some cost savings over the status quo even after the transition is complete. 

The Monitor’s proposal would break with the concept of bilaterally transferring CIRs to instead create a PJM-administered process when a deactivation study identifies transmission violations. The RTO would evaluate projects in the queue for any that could use existing headroom to resolve the violations, prioritizing those that could do so with a balance of speed and affordability. Generation developers would also be able to propose alterations to their projects or entirely new resources to meet the need. (See “Monitor Presents CIR Transfer Proposal,” PJM PC/TEAC Briefs: Aug. 6, 2024.) 

“CIRs should go back in the pool and PJM should in a parallel have an expedited process in its control to move forward with any project that can solve the reliability problem,” Monitor Joe Bowring said. He argued that the coalition proposal would grant existing generators market power through their ownership of CIRs, while the Monitor proposes that CIRs end on the date of unit retirement. 

Bowring also argued that putting the transfer of headroom under PJM’s control ensures that resources receiving CIRs are oriented toward resolving the transmission violations. It would also enable projects sited at different POIs to be expedited, including those that would require network upgrades. If no project in the queue addressed the identified reliability issue, PJM would run an auction for proposals to build new generation to address the reliability issue within a defined period of time. 

If no transmission violations are associated with a deactivation, the CIRs would be made available to projects in the general queue cycles according to their cluster position. The same would be true of any CIRs not allocated through the expedited process. Bowring argued that the value behind interconnection rights is derived from the sum total of transmission investments across PJM and thus should not be considered the property rights of developers who paid for network upgrades as part of a generation interconnection. 

“CIRs are a network resource, are essential to FERC-mandated open access, and derive their value from all the investments made by customers and generators over a long period,” Bowring said. 

Stakeholders Endorse Manual 14F Periodic Revisions

The committee endorsed a set of revisions to Manual 14F: Competitive Planning Process that remove out-of-date references and update details in the document. 

PJM’s Brian Lynn said the changes were identified during PJM’s Long-term Regional Transmission Planning (LTRTP) workshops but were not adopted as the overall LTRTP changes were not voted on. Stakeholder focus has shifted to revising long-term planning through PJM’s compliance filing on FERC Order 1920. 

First Read on Manual 21B Revisions

PJM’s Andrew Gledhill presented the first set of proposed revisions to the newly established Manual 21B, which details the rules for capacity resource accreditation. The changes would align the definition of dual-fuel combustion turbine and combined cycle units in the manual with revised Reliability Assurance Agreement definitions accepted by FERC in July (ER24-1988). 

The change allows gas generators that are capable of operating on a secondary fuel after starting on their primary fuel to qualify as dual-fuel, a change sought by Calpine earlier this year. During the earlier stakeholder process, Calpine’s David “Scarp” Scarpignato said some gas units can start on a small amount of fuel already purchased and packed into the portion of the gas pipeline on generator property, even if the regional pipeline is offline. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.) 

Transmission Expansion Advisory Committee

Supplemental Projects

During the TEAC meeting Sept. 13, FirstEnergy presented a $99.1 million project to rebuild its 138-kV New Departure substation to serve a new 540-MVA customer, with a 345-kV delivery point in the ATSI transmission zone. 

The three-phased project would begin with adjusting relay settings at the substation, work that is expected to be completed in March 2025, followed by the rebuilding of the 138-kV infrastructure already present at the site. It would be reconfigured as a breaker-and-a-half switching station with nine breakers. The second phase, to be completed in May 2028, also includes cutting New Departure into the 138-kV Nasa-Greenfield and Ford-Greenfield lines. The first two phases together are estimated to cost $27 million. 

The $72 million third phase involves building a new 345-kV ring bus at New Departure with four breakers and two 345/138-kV transformers. The facility would be looped into the 345-kV Davis-Besse-Hayes line with two new lines. An additional six 138-kV breakers would also be added to New Departure in the third phase, which FirstEnergy envisions being complete in November 2029. 

Dominion presented the TEAC with a $35 million project to construct a new Old Limb Substation serving a data center complex in Prince William County, Va. | PJM

Exelon presented a $92.1 million project to rebuild its 10-mile 230-kV Ryceville-Morgantown line in the PEPCO zone, a line that the utility said is nearing its end of life at 56 years old. The work would include replacing 55 lattice towers with steel monopoles and new conductor. The project is in the engineering phase, with a projected in-service date of April 1, 2028. 

Dominion Energy presented a $35 million project to construct a new 230-kV Old Limb substation to serve new data center load in its transmission zone. The new facility would be configured with a six-breaker ring arrangement cut into the Heathcote-Gainesville and Loudoun-Youngs Branch lines. Two new 230-kV tie-lines would be constructed between Old Limb and Youngs Branch, the latter of which would have two new breakers and terminal equipment installed. 

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CPUC Sets New Energization Timelines for Calif. IOUs

The California Public Utilities Commission on Sept. 12 approved rules requiring the state’s three large investor-owned utilities to meet stricter timelines and targets for connecting electricity customers to the grid.  

“Electricity is the fuel of our future, and the utility grid must be ready to meet customer needs for energization without delay,” said CPUC President Alice Reynolds. “This decision moves us forward by improving oversight, transparency and accountability to serve the needs of EV charging stations, new housing developments, building electrification and other customer requests for service.”  

The timelines are meant to expedite the process for new and upgraded electrical services, enhance utility accountability, offer greater transparency for customers and support California’s climate goals, according to a CPUC press release.  

The new rules apply to Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric. 

If targets are met by IOUs, maximum timelines for grid connections could be reduced up to 49% compared with current operations, increasing the speed of energization for projects reliant on electricity connections, the press release notes.  

The decision implements Senate Bill 410, known as the Powering Up Californians Act, and Assembly Bill 50, both of which direct the CPUC to define reasonable average and maximum energization timelines for new or upgraded electrical loads, publish biannual reports, establish a process for reporting delays and adopt remedial actions if they are exceeded.  

SB 410 addresses the time necessary to complete customer energization requests, including upgrades to the distribution system and the extension of new electric service. It requires the commission to, no later than Sept. 30, 2024, establish the average and maximum time an IOU should take to complete upgrades or establish new service, as well as a method for customers to report instances when those energization targets are met.  

“The bill recognizes that to meet California’s decarbonization goals, new customers must be promptly connected to the electrical distribution system, and existing customers must have their service level upgraded in a timely manner,” the decision said.  

AB 50 requires the CPUC to determine the criteria for what is considered timely energization for electric customers. It also requires “each large electrical corporation that energized less than 35% of customers with completed applications exceeding 12 months in duration by Jan. 31, 2023, to submit a report to the commission, as specified, on or before Dec. 1, 2024, demonstrating that the large electrical corporation has energized 80% of customers with applications deemed complete as of Jan. 31, 2023, as specified.” 

The CPUC’s decision sets a target for an average timeline of 182 days and a maximum timeline of 357 days for energization of the commission’s Rule 15 projects, which involve distribution line extensions for IOUs. For Rule 16, which refers to service line extensions typically associated with a single customer instead of multiple customers, the target sets an average timeline of 182 days and a maximum of 335 days for energization.  

Rule 29, which refers to EV infrastructure, shares the same timelines, and several other energization timing targets are set for application decisions, circuit or substation upgrades, and main panel upgrades.  

“As we move further along in the energy transition, we must ensure that all customers have timely access to electric service,” said CPUC Commissioner Darcie Houck. “This decision is a positive step forward in helping to meet California’s ambitious clean energy goals while appropriately balancing customer need and affordability with utility capabilities.”   

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PJM MIC Briefs: Sept. 11, 2024

Price Cap Increases in 2026/2027 BRA Planning Parameters

VALLEY FORGE, Pa. — PJM presented on how the planning parameters for the 2026/27 Base Residual Auction (BRA) affected the variable resource rate (VRR) curve, which intersects with supply and demand to determine auction clearing prices.

The curve is taking a more linear and steep shape in this auction, with the RTO-wide price cap increasing to $696/MW-day should 145,774 MW or less clear the auction. Point B, set at net cost of new entry (CONE), quickly falls to a $0 clearing price at 149,455 MW capacity clearing and remains at zero through to Point C at 153,873 MW.

The planning parameter posting comes weeks after the completion of the 2025/26 BRA and as stakeholders digest a significant jump in clearing prices, including two regions clearing at their price caps. (See PJM Market Participants React to Spike in Capacity Prices.)

Scheduled for December 2024, the 2026/27 auction will be the first to use a combined cycle generator as the reference resource (RR), which is the generation class for which the CONE estimates construction costs. Estimated net revenues for the RR and CONE values both are higher for CC generators than the combustion turbines previously used as the reference, steepening the curve and setting the maximum price higher.

The formulas defining the points along the VRR curve were also changed over the previous auction, with Point A now set at the greater of gross CONE or net CONE times 1.75, whereas the point was previously gross or net CONE times 1.5. The reliability requirement multiplier for each point was also changed.

AEP Energy Director of RTO Operations Brock Ondayko questioned whether auction design changes were intended to result in a 3,500-MW difference between clearing at the price cap or at zero.

“It’s not going to take much from allowing capacity resources to have some type or revenue to having them have zero revenues,” he said.

Market Monitor Joe Bowring said the use of gross CONE to set the maximum price on the VRR curve means that prices could reach approximately $700 per MW-day but that there is no logical or economic basis for capacity market prices at that level.

PJM’s Pete Langbein said the changes were drafted through the quadrennial review process by both stakeholders and PJM.

PJM Proposes Rules for Non-inverter Hybrid Resources

PJM presented its proposal for how non-inverter resources paired with battery storage can participate in its markets as a hybrid resource, such as a gas generator paired with storage.

The effort is the third phase in PJM’s development of hybrid market rules, with the first focused on solar and storage and the second looking at all inverter-based resources. While the hybrid model allows for different inverter-based generation types to be combined without storage, the non-inverter option requires generation and storage components.

Both inverter and non-inverter hybrids with storage would be able to provide reserves — except for non-synchronized and secondary reserve products — and be required to do so if committed in the capacity market. Generation-only hybrids would not be able to provide reserves unless granted an exception.

The make-whole and lost opportunity cost (LOC) design would be similar to the pumped-hydro rules, allowing make-whole payments for hybrids instructed to charge at a higher cost than their desired LMP, while hybrids reducing charging according to manual PJM dispatch would not be eligible for LOC payments.

The changes include several clarifications of existing market rules, including that non-inverter hybrids can provide regulation but, like inverter-based hybrids, they cannot only provide regulation. It also differentiates between station power and the storage charging mode, which must be reported to PJM separately through Power Meter.

The proposal would also clarify how generation-only inverter hybrids are subject to the must-offer requirement. The resource would be required to offer an economic maximum (EcoMax) value into the day-ahead market equal to or greater than its hourly forecast. For inverter hybrids with storage, the energy offered over 24 hours must add up to forecast generation, “grossed up” with the efficiency of the storage.

Non-inverter resources would participate in the energy and ancillary service markets similarly to the standalone storage model.

PJM’s Maria Belenky said staff have received inquiries regarding the number of existing resources that would be subject to the non-inverter hybrid rules, but PJM does not yet have a total that can be shared.

PJM Proposal Would Allow Changes to RPM Auction Deadlines

Stakeholders reacted sharply to a PJM problem statement and issue charge that would consider revising governing documents to add language saying that BRA deadlines are subject to change and the posting of planning parameters does not carry legal consequence.

The issue charge states that the notice would allow PJM to make “potential corrections to capacity market rules that are filed in advance of the commencement of the relevant auction window.”

PJM Associate General Counsel Chen Lu said the changes are being contemplated in response to the 3rd U.S. Circuit Court of Appeals vacating a FERC order allowing PJM to revise the locational deliverability area (LDA) reliability requirement for the DPL-S region in the 2024/25 BRA. The court determined that making such a change so far into the auction process would violate the filed rate doctrine. (See Following Court Ruling, FERC Reluctantly Reverses PJM Post-BRA Change.)

Adrien Ford, Constellation’s director of wholesale market development, said the expected deliverables listed in the issue charge seem overly prescriptive and would guide stakeholders towards a predetermined outcome. She also argued more language should be added around how far in advance any change in auction deadlines would have to be noticed.

Vitol’s Jason Barker said market participants need certainty around rules, and it would be imprudent to establish a paradigm where PJM can make after-the-fact rule changes in market design that mandates participation. Instead, he said, the RTO should bring concerns that arise after commencement of mandatory pre-auction activity to stakeholders and FERC for review.

Bowring said the proposal would give PJM unprecedented and inappropriate discretion over deadlines, including those related to the Monitor’s responsibilities as well as deadlines for market participants and PJM itself. In addition, he said, the suggestion that market participants cannot rely on the parameters posted by PJM is not consistent with transparency and efficient markets.

External Resource Capacity Clearing

The North Carolina Electric Membership Corp. (NCEMC) presented a problem statement and issue charge focused on how PJM accounts for external, pseudo-tied capacity resources outside the RTO’s footprint which are being committed to serve a load-serving entity.

The documents say the utility is focused on three areas: recognizing when there is a direct transmission path between external generation and LSE load; reflecting the LDA price in the region the external generation is serving in how the resource is compensated; and including that generation in LSE self-supply obligations.

When modeling and clearing capacity resources, the problem statement says, external generation is not assigned to a specific LDA, even when there is a direct path between the unit and an internal region. However, PJM does assign those resources to an LDA to assess Capacity Performance (CP) penalties or bonuses for over- or underperformance during emergencies. The practice of ensuring deliverability to the rest-of-RTO, but not to an LDA, is not reflected in the manual language.

“There is an opportunity to review certain existing provisions pertaining to external capacity resources to determine if there are modifications that would better align the external capacity resource transmission pathway with external capacity resource LDA modeling, the applicable sink LDA used in RPM clearing, and resource performance obligations and mapping. Such mismatches are particularly harmful to Load Serving Entities self-supplying resources to serve load,” the problem statement reads.

Calpine’s David “Scarp” Scarpignato said it might be prudent to also consider the interaction with the stop-loss limit to CP penalties, noting that PJM has changed the annual limit to penalties that can be assessed against a generator to be based on auction clearing prices, rather than the CONE parameter. For major emergencies, the stop-loss limit can be a more significant factor than the penalty rate for individual performance assessment intervals, he argued. (See FERC Approves 1st PJM Proposal out of CIFP.)

Bowring said the Monitor has also said there is a mismatch between external resources getting rest-of-RTO pricing, regardless of the actual electrical path it takes to be delivered to PJM.

Other Committee Activities

    • Stakeholders endorsed by acclamation revisions to Manual 15: Cost Development Guidelines drafted through the document’s periodic review. The changes focus on correcting formulas and updating section numbers. The alterations also remove a table displaying variable operations and maintenance costs, which PJM said could give a false impression that the values are fixed in the manual language; the values are updated annually and posted to its website. (See “First Reads on Several Manual Revision Packages,” PJM MRC/MC Briefs: Aug. 21, 2024.)
    • The committee endorsed by acclamation a quick fix proposal brought by PJM to eliminate the high/low and marginal cost proxy interface pricing options. PJM’s Phil D’Antonio said they have not been used since the dynamic schedule agreement with Duke Energy Progress was terminated in 2019. (See “PJM Proposes Elimination of 2 Interface Pricing Options,” PJM MIC Briefs: Aug. 7, 2024.)
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PJM OC Briefs: Sept. 12, 2024

PJM Conducts Voltage-reduction Test 

VALLEY FORGE, Pa. — The first biennial test of voltage-reduction capability was a success, PJM told the Operating Committee during its Sept. 12 meeting. 

Senior Dispatch Manager Kevin Hatch said the Mid-Atlantic region saw a 280-MW load reduction during its Aug. 14 test, coming out to about a 0.7% reduction in real-time load. PJM’s expectation was about 635 MW (1.6%). 

The western and southern regions were tested the following day, together achieving a 360-MW (0.85%) load reduction against a 920-MW (2.2%) expectation. Hatch called the test a “good, coordinated drill.” 

Conducting regular voltage-reduction testing was one of the recommendations following the December 2022 winter storm, during which an alert was issued stating that a reduction could be imminent. Following the storm, PJM told stakeholders that had a handful of additional generators tripped offline, a voltage-reduction action may have been necessary. The last time that happened was in January 2014, during the polar vortex event. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

A PJM news release regarding the test stated that no impact to consumers was reported, and the test provided the RTO and transmission owners valuable insight into how voltage actions are conducted. 

“Overall, the tests allowed PJM and its transmission owners to benefit from increased communication and understanding about the time to implement the voltage-reduction test, coordination with field personnel and evaluating the impact on the overall system,” PJM wrote. “The test also provided an opportunity to validate the operation of transmission and distribution equipment and verify equipment operating characteristics and parameters.” 

Generators experienced a 1.5% drop in reactive power capability during the test, which PJM said demonstrates a need for increasing reactive reserves to ensure transfer capability remains available. The loss amounted to 3,150 MVAr in the Mid-Atlantic and 1,300 MVAr in the west and south. 

Exelon’s Alex Stern said the operational performance data presented at the OC this month supported that PJM’s grid is delivering reliability, but stakeholders need to be proactive in ensuring that can be maintained. 

“To me this data corroborates some of what we heard [PJM CEO Manu Asthana] talk about, which is we have a really reliable grid; we just need the generation to be there, and we need to make sure we send the signals that will get the generation built … but the grid itself is functioning well,” Stern said. 

Monthly Operations Metrics

PJM’s Marcus Smith said load forecasts remained accurate through heat waves at the start of August, including a 149-GW peak on Aug. 1, though unexpectedly low temperatures during the Labor Day holiday weekend contributed to a 7% overforecast on the last day of the month. 

Most of PJM’s forecast error is driven by weather, particularly temperature, cloud cover and thunderstorms. In response to stakeholder inquiries, Smith said the RTO will look at also presenting its backcasts of how significant of a factor weather has played. 

August also saw three spin events, one of which exceeded the 10-minute mark that triggers penalties for underperforming resources. The Aug. 18 event began at 4:04 p.m. and went through 4:20 — 15 minutes and 51 seconds. A total of 1,417 MW of generation and 529 MW of demand response was committed to respond to the event, with respective response rates of 59 and 90%. A total of 630 MW of reserves face penalties for underperformance during the event. 

PJM also declared a nine-minute, 39-second spin event Aug. 12, with 1,386 MW committed and a response rate of 75%; and a four-minute, 13-second event Aug. 26, with 2,650 MW committed and a 92% response rate. 

PJM’s David Kimmel said the response rate has been low recently, which can be attributed to generation start times, as well as some resources having difficulty maintaining their committed output for the duration of the event. 

A maximum generation alert was also issued Aug. 27 because of a 9.7% generation outage rate, peaking at 17,611 MW offline, and a high load forecast. Hatch said the alert was meant to put neighboring regions on notice that interchange may have to be curtailed to serve internal load. He said both MISO and SPP were operating tightly ahead of the notice and implemented load-management procedures that reduced the need for interchange. 

Cybersecurity Briefing

Presenting the monthly security briefing, PJM Director of Enterprise Information Security Jim Gluck recommended that members ensure they have a plan for alerting the RTO to any cybersecurity breaches so staff are aware of any disruptions to expect and precautions that may be necessary to protect the grid. 

The concern stemmed from a breach at Halliburton in which customers were notified of disruptions to oilfield operations through news reports, rather than by the company. Gluck said PJM has procedures in the manuals to notify members of any breaches on its end, and sensitive information that may need to be shared can be done so through the Electricity Information Sharing and Analysis Center. 

2025 Preliminary Project Budget

PJM’s Jim Snow presented the preliminary 2025 project budget, which calls for $50 million in capital expenditures, including “historic” investments in technology. 

The forecast budget for 2024 is $44 million, while $40 million was spent in 2023 and $38 million the year prior.  

The largest share of the budget is $21 million for application replacements and retrofits, the largest of which are the energy management system (EMS) and model management software. Part of the increased funding request is the result of PJM identifying an off-the-shelf product that can accomplish much of the second phase of replacing its EMS software, leading expenditures to be concentrated in 2025 rather than spread out as planned. 

The second-largest funding area is current applications and system reliability at $18 million, including upgrades to PJM’s Dispatcher Application and Reporting Tool (DART), data analytics, credit and risk enhancements, and cybersecurity measures. The budget proposal also calls for $8 million in funding for facilities and technology infrastructure, $2 million for new products and services, and $1 million on interregional coordination. 

Snow said several items were considered for inclusion in the budget, but staff feel comfortable deferring action to avoid a larger spending increase in 2025. That includes spending approximately half a million on developing energy market incentives supporting reserve certainty and about $400,000 on expanding credit surveillance of market participants. 

The Finance Committee is scheduled to deliver a recommendation letter to the Board of Managers on Sept. 23, with board action on the budget expected in October. 

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Mass. Court Upholds Approval of Controversial Eversource Substation

The Massachusetts Supreme Judicial Court (SJC) on Sept. 11 upheld the Energy Facilities Siting Board’s (EFSB’s) approval of a controversial substation in East Boston, likely concluding the 10-year fight over the project.  

The court ruled that the petitioners, the Conservation Law Foundation (CLF) and GreenRoots, did not meet the heavy burden of proof required to overturn the EFSB’s approval of the project.  

“We conclude that the board’s decision is lawful, was supported by substantial evidence, and was not arbitrary, capricious or otherwise an abuse of the board’s discretion,” the SJC found.  

The project, currently under construction, is sited on the bank of the Chelsea Creek near a public park, homes and a new police station.  

Eversource Energy, the electric distribution company responsible for the project, had argued the substation is needed to meet load growth in the area and preserve electric reliability.  

However, the project was met with significant opposition by residents and environmental advocacy organizations, which argued it will add to the significant burden of pollution already facing the neighborhood. The surrounding area is classified by the state as an environmental justice neighborhood, meeting the definition’s criteria for income, minority population and language isolation.  

In a non-binding 2022 ballot question, 83% of Boston voters opposed the project at the selected site, while politicians including Boston Mayor Michelle Wu (D) and U.S. Sen. Ed Markey (D) have voiced their opposition to the project. 

In challenging the EFSB’s approval, CLF and GreenRoots argued the board did not adequately weigh the project’s environmental burdens with its benefits to the community and said the board improperly pre-empted the review processes of two local agencies. 

The groups also took issue with the substation’s designation as a water-dependent facility when granting its tidelands license.  

The court was not persuaded by these arguments, finding “no error in the board’s considerations of environmental protection, public health and public safety.” 

The project’s opponents expressed disappointment with the court’s ruling, arguing it is a failure to protect residents of the environmental justice neighborhood.  

“East Boston residents endure major pollution and other environmental hazards that threaten their health and safety, and this project was poorly sited in a flood-prone area,” said Anxhela Mile of the Conservation Law Foundation. Mile added that the decision underscores the “need to reform how the commonwealth permits energy infrastructure and assesses the cumulative environmental and health risks a community faces. 

“GreenRoots and the East Boston community affected by the Eversource project are disappointed with the MA SJC’s decision to allow the project to move forward, but honestly we’re not surprised,” said John Walkey of GreenRoots. “The siting and permitting process is broken from any perspective you look at it.” 

He noted that the fight over the substation was an important factor in passing environmental justice protections into state law in 2021, and in centering environmental justice protections in recent efforts to pass permitting reforms in the state.  

“We have also seen Eversource itself change its own approach to engaging communities in their recently proposed substation in the Hyde Park neighborhood in Boston,” Walkey added, noting that the company engaged the community before filing with the EFSB and “brought up the question of Community Benefits Agreements right out of the gate.” 

“However, this is cold comfort for an already environmentally over-burdened East Boston community now saddled with additional poorly and unjustly sited industrial infrastructure,” Walkey said. 

Eversource spokesperson William Hinkle said the court’s decision affirms the substation “is critically needed to address local capacity constraints, support a rapid growth in electric use and reliably serve our customers in East Boston and Chelsea.” 

“We cannot leave any customers or communities behind in the clean energy transition and achieving decarbonization and electrification goals while ensuring that all customers have access to clean energy opportunities will require a significant amount of new electric infrastructure,” he added. 

The Massachusetts Department of Public Utilities recently approved the electric sector modernization plans of the state’s three investor-owned electric utilities, establishing the framework for major new investments in electric infrastructure across the state. (See Mass. DPU Approves 1st Round of Utility Grid Modernization Plans.) 

Meanwhile, in a proposed supplemental budget bill, Gov. Maura Healey (D) included reforms to streamline and expedite the state’s clean energy permitting and siting processes. The proposal would reduce the timeline for reviewing infrastructure projects — including substations — while requiring a cumulative impact analysis to account for existing pollution sources and public health burdens, a requirement that was not in place for the review of the East Boston substation. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.) 

Hinkle noted the company has completed about 75% of the work on the station foundations, with construction expected to extend through the third quarter of 2025. The company expects the substation to come online in late 2025.  

The company estimated in late 2022 the project will cost about $103 million, compared to the initial $66 million estimate presented to the EFSB. Eversource attributed this increase to construction delays and higher costs of materials and labor.  

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NYISO Operating Committee Briefs: Sept. 12, 2024

Expedited Delivery, Interconnection Studies

The NYISO Operating Committee on Sept. 12 approved revisions to the 2024-01 Expedited Delivery Study, which found that all nine proposed projects are deliverable at their requested capacity resource interconnection service (CRIS) levels without additional upgrades.

The OC also approved the interconnection impact study scopes for the Niagara Digital Campus and Project Sycamore Orangeburg.

Niagara Digital is a 140-MW data center in Niagara Falls. Project Sycamore is a non-curtailable financial services server looking to expand its load to a maximum of 31.8 MW.

The Monticello Hills Wind interconnection study report was approved by the committee. The study found the 31.5-MW Oswego County wind farm would not have an adverse impact on the grid. The interconnection cost would be about $3.4 million.

Operations Report

Aaron Markham, NYISO vice president of operations, presented the August operations report to the committee.

Markham said August’s peak load was 28,444 MW, which occurred on the first of the month. He said this was because the month started hot, but the heat quickly tapered off.

“Now that we’re in mid-September looking at our longer-range forecasts, it looks like our summer peak was July 8 at 28,990 MW,” Markham said.

Markham pointed out emergency demand response and special-case resources had been activated in all zones across New York on Aug. 1 because of the hot weather. Additionally, 31 hours of Thunderstorm Alerts were declared.

“The only other thing of note is that we did increase the behind-the-meter solar nameplate capacity about 65 MW from last month; all other nameplate values repeat the same,” he said.

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BOEM Announces Gulf of Maine Offshore Wind Lease Sale

The U.S. Bureau of Ocean Energy Management announced Sept. 16 it will conduct an offshore wind energy lease sale on Oct. 29 for eight areas on the Outer Continental Shelf in the Gulf of Maine.

The gulf stretches from Cape Cod to Nova Scotia and the leases include areas off Massachusetts near Boston, New Hampshire and Maine. Unlike the rest of the East Coast, the Gulf of Maine has waters that are too deep for traditional offshore wind, so any projects would have to use floating turbines.

The announcement comes less than a month after U.S. Department of the Interior and BOEM announced a “research lease” that will allow the state of Maine build up to 12 floating turbines that could produce 144 MW. (See Maine Approved for Floating Wind Research Lease.)

“The growing enthusiasm for the clean energy future is infectious,” said Interior Secretary Deb Haaland. “Today’s announcement — which builds on the execution of the nation’s first floating offshore wind energy research lease in Maine last month — is the result of years of thoughtful coordination between our team, the Gulf of Maine states, industry and the Tribes and ocean users who share our interest in the health and longevity of our ocean.”

The leases could produce about 13 GW of offshore wind power if fully developed, which could power more than 4.5 million homes. Since the beginning of the Biden administration, BOEM has held five offshore wind lease sales and approved 10 commercial-scale offshore wind projects.

The announcement is based on the best available science, including an ecosystem-based spatial suitability model conducted by the National Centers for Coastal Ocean Science. BOEM also spent more than two years engaging with Tribes, the fishing industry and other stakeholders across the region to help shape the lease areas.

The overall area is about 120,000 acres less than what BOEM included in its proposed sale notice that was announced earlier this year. The bureau tried to avoid offshore fishing grounds, sensitive habitats, and existing and future vessel transit routes, while retaining enough acreage to support the region’s offshore wind energy goals.

Winning a lease does not confer the right to build an actual power plant, but it gives developers the right to submit project specific plans that would be subject to environmental, technical and public reviews before any approvals.

BOEM has identified 14 firms that are legally, technically and financially qualified to bid in the lease auction: Avangrid Renewables, Equinor Wind US, US Mainstream Renewable Power, Diamond Wind North America, Hexicon USA, Seaglass Offshore Wind II, TotalEnergies SBE US, Pine Tree Offshore Wind, energyRe Offshore Wind Holdings, OW Gulf of Maine, Repsol Renewables North America, Maine Offshore Wind Development, Corio USA Projectco and Invenergy NE Offshore Wind.

Bidders wishing to participate have to file financial forms by Sept. 27 and post $2 million deposits for each lease area they plan to bid on (up to a maximum of two) by Oct. 11.

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EHV Tx Lines Coming into Focus for ERCOT

Texas regulators are narrowing in on a reliability plan for what one said will be a “monumental infrastructure buildout” and could include 765-kV transmission to meet growing petroleum and data center demand in West Texas. 

Native West Texan Lori Cobos is the commissioner behind the quote and leader of the Public Utility Commission’s effort to add transmission infrastructure supporting the oil-rich Permian Basin. She proposed during the PUC’s Sept. 12 open meeting three regulatory proceedings to secure the reliability plan’s approval (55718). 

Cobos recommended approving local projects required to serve the Permian through 2038; authorizing transmission service providers (TSPs) to begin preparing applications for five import paths into the region; and creating a monitor to oversee the plan’s completion. 

The reliability plan builds on a recent ERCOT report that projected oil and gas load peaking at nearly 15 GW by 2038 and an additional 12 GW of data center and other non-petroleum load by 2030. The total would come to about a third of the system’s current summer peak. Based on those projections, ERCOT said building the transmission facilities to meet that load could cost up to $15.32 billion. (See SPP Considering 765-kV Solution for Permian Basin.) 

The grid operator’s staff studied two case years, 2030 and 2038, and grouped projects as either local or import paths. The local projects are independent of the study years, while the import paths consist of 345-, 500- or 765-kV options. 

ERCOT filed an addendum to the plan identifying a new endpoint for one of the import paths. It said the new endpoint would “better align” with the PUC’s recommendation allowing TSPs to begin their preparatory work while the commission decides on voltage levels. 

Commissioner Jimmy Glotfelty, who has almost a decade of experience building HVDC lines, said if he had a magic wand, he would push for 765-kV lines over 345 kV. 

“Let’s just do the 765 and get it over with, but I recognize that we’re not all there, so I think the path forward that you’ve laid out in your memo is right,” he told Cobos and the other commissioners. “The only one question that I have is the default back to 345. I would almost like that reversed, but that’s not something we need to solve today.” 

PUC staff recommends the commission adopt the 2038 case’s import path, noting 90% of the forecasting load for that year also is present in the 2030 case year. They also suggested waiting until mid-March to approve the import paths’ voltage levels. 

Representatives from the petroleum industry agreed with the approach, saying earlier is better. ERCOT also said it could work with any of the PUC’s recommendations.  

Citing concerns from the region over the need for certainty on the plan, the grid operator’s Kristi Hobbs, vice president of system planning and weatherization, said the TSPs “desire to start working on the [certificates of convenience and necessity] that take a lot of time to go through the contracting periods before they can actually file at the commission, so that allows that work to start now.” 

ERCOT is hosting a workshop at its Austin headquarters Sept. 18 on extra-high-voltage (EHV) lines. Vendors in the space will share information on supply chains, timelines, costs, construction timelines and operational characteristics of EHV lines. The grid operator also has added an EHV transmission plan to its annual Regional Transmission Plan, which will be filed in December. 

The Permian reliability plan is a result of legislation passed last year and is due Jan. 30, 2025. The PUC will consider the issue again during its Sept. 26 open meeting. 

“I think we’ll see a lot of economic development as a result of this. I think it’s going to pay for itself over time because of the amount of economic development that’s going to come as a result of that,” Glotfelty said. “765 is used in the U.S. It’s used in Canada, it’s used in Brazil, Venezuela, Russia, South Africa, South Korea and India. It’s been used since the ’60s, so this isn’t a new technology. It’s just new to us at ERCOT.” 

CenterPoint Case Delayed

The commissioners extended CenterPoint Energy’s appeal of a recent court ruling rejecting its request to withdraw its rate case, saying they want to hear from Houston residents first (56211).  

The PUC is hosting a workshop Oct. 5 in Houston to give CenterPoint customers and others a chance to weigh in on CenterPoint’s slow restoration of power after July’s Hurricane Beryl. It agreed to take up the matter during its Oct. 24 open meeting. 

“I think it’s important that before we make any decision, we go through that process and have our hearing in Houston,” Gleeson said. 

The State Office of Administrative Hearings (SOAH) in August rejected CenterPoint’s request to withdraw its rate increase to recover $6 billion of investments made since its last rate proceeding in 2019 and expand its return on equity. SOAH said the withdrawal would conflict with state law requiring investor-owned utilities in ERCOT to file a comprehensive rate review within 48 months of their most recent rate proceeding. (See CenterPoint Energy Still in Eye of the Storm.) 

The commission has been directed to file a report on CenterPoint’s restoration efforts with Gov. Greg Abbott by December. It has received more than 16,000 responses to a public questionnaire and an additional 120 responsive filings from utilities, cities and trade associations. 

Engie-ERCOT Dispute Deferred

The commission heard oral arguments but took no action on a two-year dispute between Engie North America and ERCOT over compensation for the response reserve service (RRS) the company provided during the February 2021 winter storm. It deferred making a decision until a later open meeting. 

Engie and Viridity Energy Solutions ask to be reimbursed $47.5 million or credited for the 27 MW of RRS it delivered each day during Feb. 15-19, 2021. ERCOT said the complainants did not provide the RRS after Feb. 15, citing their failure to have confirmed trades for the ancillary service in the day-ahead market during those days. Engie and Viridity contend that following normal procedures was effectively impossible during the storm, when ERCOT’s grid came within minutes of a total collapse (53377). 

SOAH’s law judges in June rejected the Engie and Viridity complaint. They found the complainants did not show that ERCOT’s actions violated any applicable law. 

At issue is the grid operator’s requirement to have capacity that supports an ancillary service trade or offer. Its protocols define capacity for noncontrollable load resources as their net power consumption minus low power consumption, which is the load available for interruption. 

Engie’s legal counsel said the load resources lost their capacity when deployed, preventing them from being scheduled in the next day-ahead market. Engie and Viridity sought remedial relief to receive $47.5 million for the service they provided during the storm. 

ERCOT says the evidence indicated Viridity benefited by not participating in the day-ahead market, avoiding $65 million in ancillary service imbalance charges. 

PUC Adopts EOP Report

The PUC also adopted staff’s recommendation to approve a report on the power sector’s weatherization preparedness and companies’ emergency operations plans (EOPs). The report is due to the state legislature, which directed the report last year, by Sept. 30 (53385). 

Business management consultant Guidehouse reviewed 691 electric entities’ EOPs, checking the grid’s ability to withstand extreme weather events in the coming year. It found the sector is “largely prepared” across the state for extreme weather, and its participants exhibit “basic” emergency preparedness programs and have measures in place to respond to weather events. 

The firm noted its review was limited in scope and did not “comprehensively” cover resource adequacy, weatherization, system-hardening efforts or spare critical inventory. Guidehouse’s suggested improvements included financial penalties for noncompliance and a greater focus on EOPs’ actions to withstand extreme weather events.  

“One example identified in multiple EOP submissions is the inclusion of a detailed list of food items needed for an entity’s staff during emergency situations … but the plans did not include strategies or equipment needs for field response,” the report said. 

About 70% of applicable entities provided EOPs or affidavits on no material changes. Guidehouse said the remaining 30% were “overwhelmingly low risk.” 

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MISO Says 2nd Long-range Tx Plan to Cost $21B, Deliver Double in Benefits

MISO said its second, mostly 765-kV long-range transmission plan will provide the Midwest region with at least a 1.9:1 benefit-cost ratio and cost $21 billion, lower than its earlier estimated $23 billion to $27 billion.

The grid operator announced the approximations at stakeholder workshops Sept. 10 and 13. Even with the slightly lower costs, MISO’s Independent Market Monitor is incredulous the portfolio would deliver nearly double its cost in benefits.

Jeremiah Doner, MISO director of cost allocation and competitive transmission, said MISO refined its cost estimate using facility-specific details.

“That number may move around a little bit. But I think that $21 billion is where the portfolio stands,” he told stakeholders. “We don’t expect at this point in the process to be adding projects, so we don’t expect that number to materially change.”

Doner said MISO tried to minimize costs by proposing to co-locate some of the new 345- and 765-kV lines with existing structures.

“We know there’s always more risk in the regulatory permitting process when you have to seek new rights of ways,” Doner said. He added that MISO is in discussions with its transmission owners about what would be the most feasible route for the line.

MISO also is exploring routing a 765-kV line on an existing 161-kV route because it will cross an “environmentally sensitive” area from Wisconsin into Minnesota over the Mississippi River, Doner said. “We recognize that’s not a common practice,” he added.

At $21 billion and roughly 4,000 line miles, the second plan doubles the first LRTP portfolio, both in terms of costs and line miles. Doner reminded stakeholders the second portfolio has been in the works since 2022, when MISO moved to establish a projection of what the system would look like in 20 years.

The Ratio

Doner said the portfolio demonstrates “at least” a 1.9:1 benefit-to-cost ratio when analyzing its projects using MISO’s nine benefit metrics, which include the advantages of decarbonization, ability to withstand extreme weather and assistance in avoiding loss-of-load events, in addition to the more mundane adjusted production costs.

“We know these assets are going to be in service much longer than that,” Doner explained, adding that MISO was intentionally conservative to show the projects will more than pay for themselves over their first 20 years of service.

Doner said if MISO assumes the lines have a 40-year lifespan, total benefits could rise to 3.8:1. He added that with the conservative estimate, all of MISO’s cost allocation zones in the Midwest region are set to experience at least a 1.3:1 benefit-cost ratio.

“I think it’s important to show at least a 1:1 benefit-cost ratio in each of the cost allocation zones,” Doner said.

On a 20-year basis, MISO estimates the second LRTP portfolio will conservatively save MISO Midwest $16.3 billion because of the mitigation of reliability issues; $15.7 billion from avoided capacity costs; $8.1 billion in congestion and fuel savings; at least $7 billion in decarbonization assistance; nearly $3 billion in capacity and energy savings from a decrease in system losses; and $1 billion in avoided transmission investment. MISO also estimates the LRTP portfolio will save the Midwest at least $392 million from the reduced risk of extreme weather and $76 million in reduced transmission outage costs.

Skepticism

However, Monitor David Patton said he continues to believe three of the nine benefit metrics (avoided capacity costs, avoided reliability risk and decarbonization) are outright invalid or overstated and if they are deleted or significantly scaled back, the portfolio’s benefits would not come close to covering its costs. (See MISO Closing in on Final, $25B LRTP; Monitor Repeats Reservations.)

“If you adjust for those metrics, the overall benefit metric goes down to 0.5:1,” Patton said, adding he thinks it is “really, really important to scrutinize” MISO’s methodology.

“This is not about reliability. This is about a choice to build generation to further others’ policy goals,” North Dakota Public Service Commission staffer Adam Renfandt said in criticizing the portfolio.

Doner said when MISO developed its 20-year outlook that the portfolio is built upon, it examined which direction members were taking “across the whole footprint, not just in pockets of the MISO system.”

MISO planner Joe Reddoch said the analysis showed the portfolio would reduce constraints and increase system capacity so the RTO can meet its capacity needs with fewer resources.

Patton pushed back on the message that MISO faithfully followed its members’ resource plans when crafting the portfolio. He said that to model resources, the RTO relied on the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS), which he said only minimizes costs in deciding what to build and ignores potential revenues entirely, leading to “very unrealistic” fleet assumptions.

Patton said he doubted the avoided capacity costs MISO has estimated and that members naturally would build more deliverable resources on the other side of transmission constraints if the transmission were never constructed. He said it’s highly unlikely members would continue to build generation in sites that are undeliverable to load. Patton added that if MISO approached its members and said it was not going to meet its resource adequacy obligations, members would adjust resource planning, which “pretty quickly” would reduce the LRTP’s benefits by “tens of billions.”

“You’ve cited an undeliverable collection of resources if we don’t build [the second portfolio], but our markets are designed to take care of that. To characterize that as a benefit is pretty misleading,” Patton said.

Doner said members have asked MISO to build a dependable system around their future plans. He also said it is not so simple for members to “move generation around,” citing wind- and solar-rich locations in the footprint.

“We have transmission planning responsibilities, not resource planning responsibilities. We really do rely on what our members are telling us that they’re going to build,” Doner countered.

Patton also said MISO is off base by establishing the value of the portfolio’s avoided reliability risks on the value of lost load (VoLL). He said in “no world” would the RTO allow reliability risks to become severe enough to shed load. Instead of lost load, Patton argued MISO should base the benefit on which transmission facilities would be built without the LRTP portfolio. MISO needs “an accurate ‘but for’ case,” in which it analyzes which shape its system will take without the second portfolio, he argued.

“Calculate something that’s real. This is not real,” Patton said. It’s “unconscionable” to expose customers to transmission investment based on “imaginary” and “massively overinflated” benefits, he said.

Jim Dauphinais, an attorney representing multiple industrial customers in MISO, said the use of VoLL in the benefit is “highly problematic.”

However, Jeff Eddy, director of transmission planning for ITC Holdings, warned stakeholders “there are big dollars behind outages” and pointed to Texas as an example. Eddy said that if anything, MISO was being conservative on the portfolio’s $16 billion reliability value.

“We know that these backbone lines really do provide benefits,” Sustainable FERC Project attorney Lauren Azar added. “I hope no one is questioning the benefits that regional backbone lines bring to the region.”

Reddoch said it’s difficult to compare the numerous, scattershot baseline reliability projects MISO would need on a five- to 10-year horizon with the 20-plus-year reliability benefits that the second LRTP portfolio would achieve. However, he said the portfolio likely would be more economical than smaller, piecemeal projects to comply with NERC standards.

“This has always been a challenge in the industry to monetize reliability,” Doner added.

North Dakota PSC Commissioner Julie Fedorchak said she was “dubious” that all MISO members would know where their projects will be located 20 years into the future, suggesting the RTO took liberties with its siting assumptions.

WEC Energy Group’s Chris Plante said he would like MISO to admit its planners fashioned a hypothetical resource expansion only with its members’ carbon reduction goals in mind. “My expansion plans don’t go out much more than seven years,” he said.

Doner said while it is not “100% member plans” that make up the 20-year future, it nevertheless comprises mostly member plans, and where there are not explicit plans, MISO sought extensive member input.

MISO Vice President of System Planning Aubrey Johnson said the RTO made “over 500 adjustments” to its original resource siting assumptions after speaking with its stakeholders throughout the planning process.

“Good golly, I really wish we could build regional backbone projects sooner than eight to 15 years in the future,” Azar said, urging stakeholders to consider the timeline to build transmission. “MISO has no choice but to essentially site the resources in the models. All modeling is necessarily wrong, but that doesn’t mean we shouldn’t be doing it. I really just urge folks to think about the reality of how long it takes to build these really big projects.”

“I’ve never known a resource planner who can tell me exactly what they’re going to do,” Eddy agreed. “This is high-level stuff, and I support what MISO is doing.” He said stakeholders seem to be losing sight of what MISO’s big-picture, future planning was intended to accomplish.

Plante said it seems MISO is rushing for December board approval rather than making sure “sound planning principles” are applied to the portfolio.

“Given the magnitude of the expansion planning here, we need to be careful that we establish sound foundations,” Plante said, adding  the projects will be subject to scrutiny at state regulatory agencies.

“We disagree that there’s a lack of analysis here. We believe this is thorough,” said Jeanna Furnish, MISO director of expansion planning.

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Equinor Yanks Request for Empire Wind 2 Export Cable

An offshore wind proposal that was placed on hiatus amid the industry’s recent financial turmoil is taking a further detour, halting its attempt to bring an export cable onshore in New York. 

Empire Offshore Wind on Sept. 12 withdrew its application (Case No. 22-T-0346) with the state Department of Public Service for a Certificate of Environmental Compatibility and Public Need for the transmission line that would have served Empire Wind 2. 

Without a certificate, Empire cannot build a line. 

The application had become highly controversial in the 27 months since it was submitted, attracting strong resistance in Long Beach, the oceanfront city it would pass through. (See ‘What Did We Do to Deserve This?’) Nearly 1,000 comments have been submitted in the Public Service case. 

Gov. Kathy Hochul (D), a vocal wind power proponent, further complicated the effort when she vetoed an attempt to facilitate construction of the cable through the city. (See New York Governor Vetoes Planned Offshore Wind Transmission Act.)  

A spokesperson for Equinor said Sept. 13 the company remains committed to development of the Empire Wind 2 lease area in a manner that is profitable and will assess future offtake opportunities. 

Both Empire plans have been approved by federal regulators, but only Empire 1 is progressing at this point. (See BOEM Approves Empire Wind.) 

Equinor anticipates a final investment decision on Empire 1 this year. The company is building an $861 million offshore wind hub in Brooklyn to service this and future projects, and it is looking for an equity partner for Empire 1. 

Empire 1’s export cable would connect with the grid in Brooklyn, in a location and manner that has not attracted opposition similar to that seen in Long Beach. 

Empire Wind 1 and 2 and Beacon Wind 1 and 2 were joint ventures of Equinor and bp; the two companies previously were awarded New York state contracts for Empire 1, Empire 2 and Beacon 1. 

The anticipated cost of construction soared in 2022 and 2023, however, rendering the financial terms of those contracts untenable, and all three contracts were canceled, along with contracts for many onshore renewable projects. (See Sweeping Reset Underway for NY Renewable Development.) 

The two companies ended their partnership and split their portfolio. Beacon went to bp, which said in June it still was evaluating its options. (See Bp Says It is Still Evaluating Beacon Wind.) 

Equinor bid Empire 1 into the rush solicitation New York launched in an attempt to get its offshore wind aspirations back on track when its portfolio collapsed. Equinor won a new contract this year for 810 MW of capacity at a much higher price than the original contract. (See Empire, Sunrise Wind Back Under Contract in NY.) 

Equinor did not rebid the 1,260-MW Empire 2 into the rush solicitation, and the spokesperson said it also did not rebid the project into the current New York solicitation, which closed Sept. 9. 

The current solicitation attracted some other familiar names, however: Attentive Energy, Community Offshore Wind and Excelsior Wind all announced that they had submitted proposals for plans that have been in the works for years. (See NY OSW: If at First You Don’t Succeed, Try, Try Again.) 

New York awarded tentative contracts to all three proposals in October 2023, but they had to be scratched in April 2024, when development of the turbine specified in those contracts was halted. (See NY Offshore Wind Plans Implode Again.)