Transmission Congestion in New England: Planning for the Future
New England poses a unique case around transmission congestion. After a decade of targeted investments, the region now boasts the lowest congestion rates in the country. However, this achievement comes with a tradeoff: some of the highest transmission costs nationwide. In this post, we’ll explore New England’s journey in addressing transmission congestion, the results of its significant investments, and the ongoing challenges facing the region.
New England's Historical Transmission Landscape
Figure 1 The Market Price Differential Metric (2017-2021), pg. 14
Figure 2 Google satellite image of New England at night
New England is a region with several populous cities, creating load pockets that are surrounded by towns and suburbs, limiting the ability of transmission developers to acquire the necessary new rights of way to build new transmission lines. This dynamic has, historically, caused two issues in New England: (1) areas with large load that cannot be served by lower cost energy (import congestion) and (2) areas with a surplus of renewable energy that are unable to export generation to the rest of the grid (export congestion). In Figure1, these areas are respectively designated with the colors red and blue. Figure 2 shows a satellite image of New England at night, where the dark areas in Maine, Vermont, and New Hampshire correspond to the blue congestion zones, and the bright areas to red congestion zones. The bright areas in Massachusetts and Connecticut represent the historically congested Lower Southeast Massachusetts (Lower SEMA) and Norwalk-Stamford zones as defined by ISO-New England.
In 2006, the Department of Energy (DOE) designated New England as a “Congested Area of Concern” in their National Electric Transmission Congestion Study. This designation indicated that, without intervention, a large-scale congestion problem was expected to emerge. To address these challenges, ISO New England (ISO-NE) and transmission owners embarked on major infrastructure projects. By the 2017-2021 period, congestion and congestion pricing in historically constrained areas, including Lower SEMA and Norwalk-Stamford, had improved, resulting in historically low congestion on the system.
Ratepayer Impacts and Balancing Costs
Although these measures successfully reduced congestion, these projects came at a significant cost to the region's customers who ultimately bear the long-term burden of paying for these investments. What New England saves in congestion costs is balanced out by the region’s transmission costs of $22/MWh of load—33 percent higher than in the PJM regions, even though, historically, the demand for electricity is almost 6 times greater in PJM than in ISO NE.[1]
It is also important to consider that many of these congestion-reducing investments alleviated congestion in the southern New England states. However, since these investments are seen as improvements to the New England transmission system’s ability to reliably transport energy, all ratepayers in all of New England see the costs reflected on their electricity bills. This is contentious in states like Maine, where previous large projects to improve regional reliability did not consider the present and future needs of local customers, prioritizing reliability needs of southern New England. Energy bills throughout New England will increase to cover the investment costs, regardless of a single state’s inclusion in the planning process. Projects constituting significant regional investment must emerge from a coordinated regional planning process.
Ultimately, the $12.1 billion of transmission investment made in the 2000s created headroom on the New England grid and likely alleviated the need for near term transmission expansion. Though contentious, these investments have provided a more reliable and efficient grid for the entire region. However, as we look toward the future, achieving an equitable balance of costs and benefits will require proactive regional planning and cooperation.
Looking Ahead in New England
New England’s successful efforts to reduce congestion in the 2000s provide valuable lessons as the region faces the next phase of transmission planning. With aggressive renewable energy targets and growing electricity demand, the region must expand its transmission system again—but this time with a forward-looking, equitable, and cost-effective approach.
Five of six New England states have adopted renewable portfolio standards requiring at least 80 percent renewable energy by 2050, and four of those states have a 100 percent renewable goal. Reaching these goals means not only replacing existing generation with renewables, but also keeping pace with the 10 percent load growth. ISO predicted in the 2024 Capacity, Energy, Loads, and Transmission (CELT) Report. ISO-NE is anticipating up to a 57 GW peak load in 2050.
Key Challenges:
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Load growth will likely be driven by electrification and population growth in southern areas, meaning that while southern New England states will likely need to import renewables to meet their RPS goals, northern New England states will not. The buildout to support this will cost between $23-$26 billion, almost half of which is allocated to the Boston area. This plan will not be universally popular throughout the region, and consensus building through regional planning will be required to design an equitable and reliable transmission network. Fairly distributing the costs and benefits to the entirety of New England will be a challenge in future decongestion and decarbonization efforts in the region. In the context of enabling renewable generation, everyone benefits. However, decongesting transmission so low-cost renewables in the North can serve southern New England benefits ratepayers in southern New England, and the renewable generators able to supply them. For ratepayers in northern New England, rates increase due to the loss of the negative congestion price and through the socialization of transmission cost recovery. Regional planning efforts are critical for building consensus and planning for cost-effective investment.
- Additionally, renewable generation will be more distributed and location-dependent than fossil generation, intensifying the role that the siting of resources plays in transmission expansion. New England’s approach to transmission expansion in the 2000s has been reactive to areas of high congestion and reliability risk, which fails to take into account the density of renewable resources in the proximity of a transmission project. This approach risks making investments that are not cost effective and does not solve import and export congestion issues in constrained regions with high renewable energy development. Scenario-based planning uses multiple possible clean energy pathways to create transmission plans so New England can be prepared with cost-effective solutions for multiple outcomes of the clean energy transition. Cost-effectiveness is not the only concern with reactive planning, this approach will also increase tensions between the import and export constrained regions.
How to Move Forward
New England’s energy transition will demand more than just expanding its transmission system—it will require collaboration, innovation, and careful consideration of both costs and equity. Efforts like ISO-NE’s 2050 Transmission Study and FERC Order 1920 compliance are promising steps, but the journey is far from over. Proactive, scenario-based planning is crucial to addressing future challenges, and regional collaboration will be key to achieving cost-effective and equitable transmission expansion. Right-sizing grid investments when old lines are rebuilt to serve the needs of the grid of the future rather than the grid of the past will be another critical tool to ensuring efficient and cost-effective transmission planning. By planning strategically, New England can lead the way in building a reliable, equitable, and decarbonized grid for the future.
Check out our first post in this series, for an overview of what transmission congestion is, why it matters, and the key challenges it presents in our clean energy transition.
[1] FERC. 2024. “2023 Common Metrics” (January 31,2024). https://www.ferc.gov/media/2023-common-metrics page 53 figure 5.