Planning the Future Electric Grid: The Need for An Independent Transmission Monitor

Executive Summary

ISO New England, the regional electric grid operator, has estimated that the cost of expanding the transmission system to accommodate New England’s future demand for power will be between $16 billion and $26 billion. The $10 billion separating ISO New England’s high and low estimates is not just due to uncertainty about the future: it is largely due to uncertainty regarding how well the future transmission system will be planned, which will in turn determine the efficiency of that future system and its ultimate cost. Currently, proposals to improve and expand the transmission system are developed according to separate and distinct planning processes. The failure to coordinate these disparate processes threatens the efficiency of the future transmission system and places the region on a path to spend far more than is necessary to build it. An Independent Transmission Monitor (ITM) would look across current transmission planning processes to ensure that future proposed improvements to and expansions of the transmission system are harmonized to maximize system efficiency overall while minimizing their aggregate cost.

Why is an Independent Transmission Monitor Needed?

New England’s peak electricity demand – measured when the region’s demand for electricity is higher than any other time of the year  – is expected to double in the next quarter century.^[1] ISO-New England has estimated that the cost of increasing the capacity of the transmission system to meet that doubled peak will be between $16 billion and $26 billion dollars.^[2] Currently, there are multiple, distinct processes for assessing the current and future needs of the transmission system. They are the Regional System Planning (RSP), Asset Condition Project (ACP), and Local Transmission Service (LTS) planning processes. Unfortunately, there is no coordination among the RSP, ACP, or LTS planning processes—transmission investments approved pursuant to any one of the three planning processes do not account for transmission investments approved pursuant to either of the other two. This lack of coordination is producing a patchwork of transmission system upgrades that fail to take the efficiency of the entire system into account, fail to incorporate available technologies that would enhance the operation of the transmission system, and increase rather than reduce the region’s need for future transmission investments.

The largest share by far of recent investments in transmission infrastructure has been ACPs—projects to repair, upgrade, or replace aging transmission equipment in existing rights of way. Since 2018, $4.1 billion has been spent on ACPs, compared to $2.2 billion spent on reliability projects—projects to build new transmission in new rights of way—developed pursuant to the RSP planning process.^[3] At least $5.4 billion more in ACP investments are projected through 2030—again outpacing planned spending on RSP reliability projects over that period.^[4] The concern regarding the magnitude of ACP investments is not that the region is spending more to upgrade existing transmission instead of building new transmission. Rather, the concern is that 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. 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. Moreover, the failure of ACPs to increase capacity in existing rights of way will require additions of capacity in the form of new transmission in new rights of way, with all the environmental, community, and economic impacts associated with new construction. Building new transmission would cost much more and take much longer to build—five to ten years—than upgrading the region’s existing 9,000 miles of transmission lines.

Why are opportunities to optimize ACPs being missed, and why aren’t necessary increases in capacity being efficiently allocated between transmission in existing and new rights of way? Because RSP and ACP planning processes are separate and siloed: ISO New England is responsible for RSP planning while ACP planning is delegated to the entities that own the regional transmission system. (ISO New England operates but does not own the transmission system.) Moreover, transmission owners have near total discretion in planning ACP projects and are not required to consider cost-effective alternatives to the like-kind replacement of aging transmission equipment. For example, Grid Enhancing Technologies (GETs)—hardware and software solutions that improve the efficiency and capacity of existing transmission—are often overlooked by transmission owners as they plan ACP projects, even though their cost-effectiveness has been well-documented. For example, a $300,000 investment in GETs by the Pennsylvania utility PPL saved approximately $50 million in avoided project costs and an additional $20 million each year in grid congestion charges^[5]. Neither are transmission owners required to consider the installation of high-performance conductors (HPCs)—which can carry up to twice the power carried by conventional transmission lines^[6]—as part of their ACPs. HPCs also avoid many of the costs associated with building new transmission in new rights of way, typically costing less than half the price of new lines for similar capacity increases.^[7]

LTS projects—projects to address reliability concerns within a transmission owner’s service territory–suffer the same deficiencies as ACPs. Transmission owners plan and develop LTS projects to address the needs they identify, entirely at their discretion. And, as with ACPs, transmission owners are not required to consider GETs and HPCs as cost-effective measures to maximize the efficiency of their LTS projects.^[8]

The Role of the Independent Transmission Monitor

The ITM would not be associated with any of the entities—ISO New England or transmission owners—responsible for the RSP, ACP, or LTS planning processes. Further, the ITM’s authority to review proposed transmission projects would extend across the RSP, ACP and LTS planning processes.^[9] The ITM would be responsible for ensuring that transmission projects of every type, size, and scope were designed to include all cost-effective measures to increase the efficiency and capacity of the entire transmission system. The result would be the optimization of transmission in existing rights of way, the minimization of the need for new transmission in new rights of way, the adoption of technologies to enable the efficient routing of power across the entire transmission system, and the development of projects that are fully integrated into a planning process that is comprehensive–and not restricted–in scope.

Next Steps in Developing an ITM

While ISO New England is supportive of an ITM that would respond to the New England states or FERC, it has not taken the initiative to establish one.^[10] Because incumbent transmission owners receive a fixed rate of return on their transmission investments they lack the incentive to support an ITM that would recommend cost-effective alternatives—GETs and HPCs—and other measures that would reduce transmission investments overall. Responsibility for the establishment of an ITM thus lies with the six New England states. Acadia Center believes that an ITM is essential to eliminating the inefficiencies inherent in New England’s disaggregated transmission planning processes and supports the establishment of an ITM with sufficient resources to meet its engineering, financial, and regulatory responsibilities to stakeholders. Acadia Center will work to encourage and support the initiatives of the New England States Committee on Electricity,^[11] state consumer advocates, and other interested stakeholders to establish an ITM, continue to build public awareness regarding the threat that unbounded transmission investments have on energy affordability, and foster consensus regarding the need for transmission planning reform.

Acadia Center Recommendations

Acadia Center is working to raise awareness of the need for an ITM and for public oversight of the billions of dollars in transmission upgrade projects proposed by utilities and transmission owners. We are working to support efforts by states and NESCOE to create an ITM for the ratepayers of New England and to prioritize the creation of an ITM in the region. Acadia Center is working to identify the key components of an effective ITM.  Please contact us at info@acadiacenter.org for more information or visit www.acadiacenter.org.

[1] “The Energy is About to Shift,” Acadia Center and Clean Air Task Force (Dec. 2024), p. 5. https://acadiacenter.wpenginepowered.com/wp-content/uploads/2024/11/AC_CATF_EnergyShift_Report_2024_R10-1.pdf

[2] 2050 Transmission Study, ISO New England Inc. (Feb. 2024), p. 16. https://www.iso-ne.com/static-assets/documents/100008/2024_02_14_pac_2050_transmission_study_final.pdf

[3] CT GENERAL STATUTES – SECTION 16A-3A 2025 INTEGRATED RESOURCES PLAN – Transmission Solutions White Paper (February 26, 2025), pp. 5-6. https://portal.ct.gov/-/media/deep/energy/transmission/transmission-white-paper-final.pdf

[4] Id. at p. 6.

[5] “Regulators need to require utilities to use grid-enhancing technologies: FERC’s Clements,” Utility Dive, Nov. 14, 2023) https://www.utilitydive.com/news/transmission-grid-enhancing-technologies-gets-utilities-naruc-ferc-clements/699686/

[6] Emilia Chojkiewicz et al., “2035 and Beyond: The Report—Reconductoring,” GridLab, 2024, p.3. https://www.2035report.com/wp-content/uploads/2024/06/GridLab_2035-Reconductoring-Technical-Report.pdf.

[7] Id.

[8] CT GENERAL STATUTES – SECTION 16A-3A 2025 INTEGRATED RESOURCES PLAN – Transmission Solutions White Paper (February 26, 2025), p. 6. https://portal.ct.gov/-/media/deep/energy/transmission/transmission-white-paper-final.pdf

[9] Last December a coalition of electricity consumers filed a Complaint with the Federal Regulatory Commission (FERC) against more than two dozen utilities and all the major grid operators, including ISO New England, asserting that FERC should prohibit transmission owners from independently planning LTS projects and assign LTS planning authority to an ITM. See https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20241219-5368&optimized=false

[10] ISO New England Board of Directors’ Response to 2024 Open Board Meeting Comments (February 5, 2025) p.3 https://www.iso-ne.com/static-assets/documents/100020/iso-board-response-to-2024-open-board-meeting-comments.pdf

[11] Comments on Transmission Planning and Cost Management (March 29, 2023) https://nescoe.com/resource-center/comments-on-transmission-planning-and-cost-management/