Asset management projects, asset refurbishment, asset condition, local and supplemental projects—they all refer to a category of transmission projects responsible for a sharp uptick in overall transmission investment throughout the nation.

These projects generally refer to smaller, local lines within a single utility jurisdiction, often for the repair and maintenance of existing assets. Locally planned lines are subject to far less regulatory scrutiny than other transmission investments (i.e. “the regulatory gap”). In the last ten years, asset condition and local project spending has steadily increased and now represents the majority of new transmission investment.

While some spending on local and asset condition projects is necessary, these investments are a piecemeal, siloed, and inefficient approach to build out the grid. If we fail to scrutinize spending on local projects, we risk wasting precious ratepayer dollars during an age where electricity affordability is increasingly paramount.

Local projects offer utilities a low-risk investment opportunity with high financial returns. Local projects do not have to undergo competitive bidding processes like many regional projects do under FERC Order No. 1000 and 1920. Moreover, under FERC's formula rate construct, utilities are presumed to have acted prudently unless stakeholders can prove otherwise—a high burden given the lack of access to internal utility data and decision-making rationale.

As a result, utilities are not subject to rigorous public justification of the need, cost, or alternatives considered for a given project. This process makes it difficult for regulators and consumer advocates to assess whether these projects are in the public interest or if more cost-effective, regional alternatives exist.

Data Supporting the Problem

• Transmission investment reached an all-time high in 2023, yet only 55 miles of high-voltage lines were built—a stark contrast to the 4,000 miles added in 2013.
• 90% of recent transmission spending has been on lower-voltage reliability upgrades; 50% has gone to local projects.
• In PJM, spending on local projects increased 26-fold from 2009 to 2023.
• ISO-NE saw an eightfold increase in asset condition projects from 2016 to 2023.
• In MISO, the share of local projects rose from 54% in 2017 to 78% in 2022.
• CAISO reported 63% of transmission projects from 2018 to 2023 were self-approved and exempt from review.

If left unchecked, asset condition and local project spending will cost consumers billions in unnecessary expenditures and produce a less reliable transmission system. State regulators, consumer advocates, grid experts, and others all caution that to rectify this mismanagement, we must address the regulatory gap and redirect investments to longer-term, holistic, regionally-planned projects to efficiently and cost-effectively expand the grid.

Read more about the regulatory gap here.

To meet long-term energy goals, the nation must triple its transmission capacity by 2050, yet current investment levels fall far short—resulting in an estimated $40 billion annual shortfall by 2031. Most new transmission is developed and financed by investor-owned utilities (IOUs), whose costs are recovered from ratepayers through utility bills.

This financing model has already contributed to a nearly 50% increase in rates for many IOU customers over the past three years and presents a growing risk: future grid investments, while necessary to maintain reliability and drive cost savings over time, could further raise energy costs in the near-term. To avoid this outcome, proactive reforms are needed to reduce the cost burden on consumers. Solutions include equitable rate reform, deployment of grid-enhancing technologies, and new public financing mechanisms that could lower project costs and ensure the grid buildout advances in a more affordable, efficient, and equitable manner.

Legislative example:

• California AB 825 - Proposes to establish a public financing mechanism to reduce costs associated with the development of eligible transmission projects.

Read a report about public financing of transmission by the Clean Air Task Force

A transmission authority is a public entity established by a state to advance long-term electric transmission development. These authorities help overcome fragmented planning and permitting processes by serving as centralized, mission-driven advocates for the state’s transmission needs.

They can identify high-priority projects, coordinate across utilities and regions, streamline permitting, and access or deploy public financing. With legal authority to plan, co-develop, and fund transmission infrastructure, transmission authorities can play a critical role in aligning grid development with state energy, reliability, and economic goals.

Well-designed authorities also create transparency and accountability through stakeholder engagement, public reporting, and a strong focus on reliability, affordability, and equity.

Legislative examples:

• New Mexico HB 188: Renewable Energy Transmission Authority (RETA)
  Established in 2007, RETA was one of the first public transmission authorities in the U.S. RETA partners with private developers and uses bonding tools to advance major multistate projects. RETA helped deliver the Western Spirit line (800 MW) and is a key partner on the SunZia project (3,500 MW capacity), demonstrating how public leadership can unlock private capital and accelerate buildout.
  
  
• Colorado SB 21-072: Colorado Electric Transmission Authority (CETA)
  Established in 2021, CETA was created to accelerate project development and help Colorado participate in organized regional transmission markets. CETA identifies priority projects, selects developers, facilitates partnerships, and ensures state access to federal grid investment programs.

Advanced transmission technologies (ATTs) include infrastructure, hardware, and software solutions that cost-effectively increase the capacity and resilience of the transmission grid. They are critical to optimizing the grid to meet increasing energy demand, integrate renewable resources, and enhance system reliability and resilience.

[LINK GETs VIDEO]

ATTs include but are not limited to:

• Advanced Conductors: High-efficiency wires that reduce energy losses and increase current-carrying capacity.
• Grid Enhancing Technologies (GETs):
  • Dynamic Line Ratings: Real-time monitoring tools that adjust the capacity of transmission lines based on weather and operating conditions, enabling the grid to handle more electricity safely.
  • Advanced Power Flow Controllers: Devices that reroute electricity to optimize grid use and relieve congestion.
  • Topology Optimization: Software solutions that reconfigure the grid dynamically to maximize efficiency and minimize congestion.

ATTs like GETs  and advanced conductors are cost-effective, proven solutions that leverage existing infrastructure to make the grid more efficient, reliable, and responsive. Policymakers across the country have introduced legislation aimed at mandating utilities to consider these technologies as part of their transmission or energy plans.

• New Mexico – HB 93 (2025) - Requires public utilities to consider ATTs in their integrated resource plans (IRPs) and distribution cooperative utilities to include ATTs in their annual reports to the Commission. Utilities that pursue approved projects may recover approved costs.
• Connecticut SB 4 and HB7017 - This bill aims to provide nearly $400 million in annual savings for Connecticut consumers by reducing electric bills. It also seeks to lay the groundwork for longer-term reductions in public benefits charges and cuts in supply, delivery, and transmission fees. Additionally, this package includes language from HB 7017, which requires electric distribution companies or transmission owners to consider advanced transmission technologies in their transmission plans and demonstrate the cost-effectiveness of these technologies. 
• Utah – HB 212 (2025) - For IRP, rate case, or other proceedings where transmission expansions are proposed, utilities must analyze ATT alternatives for cost effectiveness and other benefits (such as increased capacity, congestion relief, or wildfire risk reduction). Commission may approve recovery of prudently incurred costs. Utilities must also include a summary of existing and planned ATTs in each IRP. 

Across the country, large-scale transmission development is increasingly slowed by complex and lengthy permitting and siting disputes. Transmission developers can face years of legal challenges, pushback, and regulatory uncertainty when seeking approval for new greenfield corridors. In some cases, transmission projects are abandoned altogether due to insurmountable opposition or regulatory fatigue.

At the same time, public infrastructure corridors such as highways, railroads, and pipeline routes already traverse many of the regions where additional transmission capacity is needed. These corridors offer an underutilized opportunity: they are already disturbed, frequently state- or federally-managed, and in many cases have the physical space or easement structure to accommodate co-located transmission lines with minimal additional environmental or community impact.

• Colorado HB 25-1292 In 2025, Colorado enacted HB 25-1292, establishing a formal pathway for transmission developers to co-locate high-voltage electric transmission lines within state highway rights-of-way. The legislation prioritizes siting along existing utility corridors first, then along highway corridors, before considering greenfield routes.
• Minnesota HF 5242a In 2024, Minnesota passed a transportation omnibus bill that opened all state and interstate highway rights-of-way for the co-location of high-voltage electric transmission infrastructure. Prior to the legislation, utility infrastructure was prohibited in controlled-access highway ROWs.