Additional Economic Study Results

At the ISO-NE Planning Advisory Committee (PAC) on March 19, Richard Kornitsky and Ellie Ross of ISO-NE presented the results of additional modeling scenarios for ISO-NE’s 2024 Economic Study, which aims to evaluate the effects of state and federal policies and changes to the region’s resource mix through 2050. 

Previous findings of the study have illustrated how the region’s resource needs are expected to shift in the 2040s as the power system decarbonizes, corresponding with an exponential increase in the cost of additional carbon reductions. (See “2024 Economic Study,” ISO-NE Details Evaluation Models for Transmission Solicitation.) 

Building on the prior results, ISO-NE modeled a scenario evaluating the retirement of thermal resources. The model found the region could retire “up to 5,550 MW of legacy thermal (non-nuclear) generation” by 2050 without exceeding the loss-of-load expectation (LOLE) threshold, which was set at 0.1 days per year with a loss-of-load event. 

“The retirement of 5,550 MW of legacy thermal generation has minimal impact on system operations in the 2050 production cost model,” Ross said. “In the model with retirements, this generation is easily replaced by remaining [natural gas] generators.” 

She noted that the scenario caused a decrease in generation from thermal resources that burn landfill gas, municipal solid waste and wood waste solids, which resulted in an overall increase in the emissions from natural gas and oil. 

ISO-NE also modeled scenarios featuring increased capital costs for offshore wind (OSW) resources and no OSW buildout. 

Adopting the National Renewable Energy Laboratory’s conservative cost estimates for OSW — instead of the moderate estimates used in the model’s base case — increased total annualized build costs by about $17 billion, or 10.8%. 

This cost estimate still was cheaper than the no-OSW scenario, which increased build costs by about $26 billion, or 16.6%, compared to the base case. 

“New England needs new OSW resources to meet state emission goals at the lowest cost,” Ross said. “The buildouts with less or no OSW must rely more on emitting generation, [small modular reactors] and new [solar] resources.” 

“Even if OSW capital costs are higher than current estimates, the system will economically benefit from new OSW resources, although the ideal time frame for building OSW shifts to after 2040,” she said. 

Asset Condition Projects

Rafael Panos of National Grid introduced an asset condition project (ACP) to replace wooden structures, insulation, conductor and shield wire on a 115-kV line in Massachusetts.  

The wooden poles set to be replaced, which have an average age of 30 years, have significant woodpecker damage, Panos said. He said the population of woodpeckers in New England has grown in recent years, causing significant damage to wooden transmission structures. 

The company plans to replace the wooden poles with steel structures; Panos said he has observed woodpeckers pecking at steel structures, “but fortunately, they were not able to get through.” 

The project’s projected cost is $19 million, and the expected in-service date is the second quarter of 2026. Stakeholder comments are due April 2.  

Panos also presented a cost update on a project overhauling a substation in Tewksbury, Mass. The company has increased its cost estimate on the project to about $67 million, compared to the $36 million estimate presented in 2022.  

The increase was driven by additional issues found at the substation and rising costs of labor, equipment, materials and permitting, Panos said. 

Project List Update

New England transmission owners (TOs) have added 10 ACPs to ISO-NE’s tracking list since the previous update in fall 2024, said Brent Oberlin, executive director of transmission planning at ISO-NE. (See New England Transmission Owners Issue Draft Asset Condition Forecast Database.) The TOs estimate the projects collectively will cost about $730 million.  

ACPs categorized in the database as proposed, planned or under construction total $5.97 billion, while the total cost of in-service ACPs is $5.36 billion.  

This estimate does not include a series of projects proposed by Eversource to replace its network of underground high-pressure, fluid-filled transmission lines in Eastern Massachusetts. The company estimates the first phase of these replacements will cost between $1.5 and $2 billion and plans to provide more detailed cost estimates to the PAC in the summer. (See Eversource Outlines Billions in New Boston-area Asset-condition Needs.) 

ACP costs in New England have ballooned in recent years, spurring calls from some consumer advocates for more transparency and oversight to ensure projects are cost efficient and right sized to account for future transmission needs. 

“Despite the eye-watering sums being spent on ACP upgrades, they are not being designed to maximize the amount of power that can be carried via transmission lines in existing rights of way,” the Acadia Center wrote in a recent blog post. “Each ACP that fails to maximize the capacity of existing transmission represents a lost opportunity to prepare New England to meet the projected doubling of the region’s peak demand.” 

Connecticut 2034 Needs Assessment

Sarah Lamotte, transmission planning engineer at ISO-NE, presented the results from ISO-NE’s Connecticut 2034 Needs Assessment, which is intended to “identify the time-sensitive and non-time-sensitive needs in the study area.” 

The study identified time-sensitive minimum load needs at 21 of the 115-kV buses, and 27 of the 345-kV buses in the region. 

Lamotte said the study considered non-transmission solutions and found they would not alleviate the time-sensitive issues. She said ISO-NE plans to initiate a solutions study in the second quarter of 2025 to address the identified needs. 

Boston 2033 Solutions Study

Aqeel Ahmed, associated engineer at ISO-NE, presented the preliminary results of the RTO’s Boston 2033 Solution Study, which is intended to address time-sensitive, minimum-load, high-voltage needs.  

The preferred solution identified includes the installation of a 115-kV reactor and protection systems upgrades at five substations. The projected cost is $26 million.