Why It Matters

The U.S. not-for-profit power sector is currently grappling with multiple competing goals, including decarbonization targets and mandates, managing power intermittency, demand growth, and the phasing out of fossil-fuel generation. Achieving these goals hinges on the building out and upgrading of transmission lines and the concurrent replacement of aging generating units. However, a costly and time-consuming backlog of interconnection applications from new, renewables-based projects is causing delays. In addition, costly infrastructure, siting, and materials procurement costs, as well as labor scarcity, are challenging, and could potentially delay, not-for-profit utilities' response to adopted or anticipated decarbonization mandates.

What We Think And Why

S&P Global Ratings believes that long delays in gaining grid interconnection approval require that not-for-profit electric utilities plan for generation needs further in advance. Delays could ultimately affect credit quality of not-for-profit rated utilities within this sector if management teams struggle to achieve regulatory compliance with decarbonization requirements.

How we got here: the interconnection queue backlog

The U.S has a total of seven Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), as well as numerous non-ISO transmission operators tasked with maintaining adequate energy-generating units and transmission lines to meet regional demand. These organizations approve the connection of generation projects to the power grid to maintain consistent power flow through their individual regions.

The list of projects seeking approval to connect to an operator's transmission network is referred to as the interconnection queue. Historically, each transmission operator has maintained its own interconnection queue, as guided or mandated by the Federal Energy Regulatory Commission (FERC) where applicable.

Before 2020, a first-come, first-served approach to entering the queues worked well for developers seeking to connect large-scale generation projects to the grid. Project withdrawals, while still common before 2020, typically occurred during the early stages of planning and study, reducing the time an ISO, RTO, or other transmission operator lost in the planning stage if a project ultimately withdrew (this report may refer to RTOs, ISOs, and transmission owners interchangeably). In addition, withdrawals did not affect reliability planning to the current extent, as the level of national electricity consumption had remained fairly flat in the years since 2000 and existing generation units were not retiring to the degree they are today, easing reliability concerns.

Chart 1

However, commencing around 2020, this well-established process started to run into challenges caused by an unprecedented increase in the number of generation projects entering the interconnection queues. This influx of projects is contributing to the lengthening time it takes to bring projects to commercialization, pressuring the not-for-profit utilities' long-term reliability planning. By 2023, the cumulative capacity of active projects was nearly three times larger than the active planned capacity in 2020 (approximately 2,600 gigawatts [GW] in 2023 versus 960 GW in 2020, according to the Lawrence Berkeley National Laboratory 2024 report). Energy transition investments buoyed by recent federal stimulus funding led to a significant number of smaller-scale renewable projects entering the queue, including wind and solar and projects without a track record of successful commercialization such as hydrogen fuel cells, carbon sequestration and storage, large-scale battery, and small modular reactors. The ISOs and RTOs were poorly equipped to absorb the massive increase in projects, creating sizable backlogs. Also, in response to the growing queues, many developers submitted their connection requests prior to securing site control, state and local-level approval, or grant award confirmation. As a result, ISOs would undertake time-consuming feasibility, impact, and facility studies on behalf of projects that did not ultimately move ahead, inefficiently using valuable time.

Chart 2

The current backlog of queue requests and the diminishing capacity of transmission lines, which will require extensive build-out to accommodate the incoming generation, will likely significantly delay projects that entered the queue in the past three years. These delays, compounded by growing uncertainty around individual projects progressing to commercialization, raise doubts as to whether new generation will come online in time to meet planned generation retirements and increasing energy demand within territories served by not-for-profit electric utilities.

Regional operators face unique challenges amid growing generation retirement and load growth patterns

The effects of the backlog are being compounded by a long-term trend of retirements of fossil-fuel generation plants, which have led to significant losses of dispatched power onto the grid. Between 2020 and 2023, more capacity was retired in the U.S. than in all of the 2000s. According to the Energy Information Administration (EIA), a further 40 GW, or 3% of current U.S. total capacity, is scheduled to be retired between 2024 and 2027. In short, not-for-profit electric utilities are facing a triple threat of growing delays, capacity retirement, and escalating demand.

Chart 3

Retiring generation is an acute pressure for not-for-profit utilities that operate within ISOs that rely on transmission to convey energy from low-cost resources in distant regions. Renewable resources have much greater spatial requirements than thermal generation with similar capacity and must be placed in locations with specific attributes that are conducive to renewable dispatch, and are therefore frequently sited in locales that are distant from existing transmission lines, adding to integration costs. Although renewable generation capacity additions continue to increase significantly, their effective load-carrying capacity generally lags relative to nameplate capacity due to intermittency and energy production during concentrated windows rather than throughout the day at times that correspond with demand. Storage, such as batteries can temper intermittency by shifting output to periods when intermittent resources are dormant. 

Prompted by these challenges, in late 2023 FERC issued Order No. 2023 in an effort to deter low-feasibility projects from entering the queues, primarily through larger project-withdrawal penalties and increased financial commitments for developers, such as requiring proof of site control. See table below for more information.

In May 2024, FERC issued Order No. 1920, mandating that each RTO and ISO produce 20-year transmission adequacy studies that are to be updated every five years. This allows for improved long-term project planning and incentivizes the building out of large regional transmission corridors that address long-term needs, rather than approving smaller projects on an individual basis. The goal is to promote coordinated transmission buildout through projects that otherwise could be too expensive for any small number of participants to bear singlehandedly. As per the order, the costs of this longer-term planning, which will run into millions or billions of dollars, will be allocated across benefitting members according to value received based on seven criteria, including:

• Expected cost reduction due to avoided transmission investment to address reliability;
• Reduced generation requirements to meet peak growth; and
• Mitigation of costs that would have been incurred without the transmission project.

Many potentially affected not-for-profit electric utilities raised concerns with the cost-allocation strategy on the grounds that it could require higher project payments compared to those incurred even if a project did not proceed. To address this, FERC established a six-month engagement period to provide project participants with time to mutually agree on beneficial final cost-allocation strategy.

Anticipated results of Orders No. 2023 and No. 1920

FERC believes that Order No. 2023 will help deter low-feasibility projects from entering the interconnection queues and thereby limit time-consuming feasibility and interconnection studies for projects that might not come to fruition, while Order No. 1920 will streamline cross-regional coordination in transmission expansion projects. Together, it is hoped, they will lessen approval wait times, prioritize more feasible projects, and provide adequate transmission once projects come online.

The Current State Of The U.S. Interconnection Queue Backlog

Potential Credit Impact For The Not-For-Profit Electric Utility Sector

S&P Global Ratings believes that growing credit risks related to generating-station and transmission line buildout delays will compound other escalating costs, including capital plan investments, that not-for-profit retail and wholesale electric providers must pass on to consumers who are already facing eroding purchasing power related to escalating costs of goods and services. This could pressure rate-making flexibility, ultimately pressuring issuers' cost recovery and financial metrics.

As the energy transition accelerates, we believe that the not-for-profit utilities we rate will continue navigating a complex regulatory and logistical environment that will require enhanced long-term planning for transmission buildout, demand growth, and decarbonization.

Some large not-for-profit wholesale utilities are better equipped to navigate the challenges than smaller not-for-profit utilities given the size of their customer bases and their generally more sophisticated management, allowing them to collaborate with states, ISOs, and federal-level policymakers on inter-state collaboration, federal funding, and project cost allocation.

In addition, some smaller, distribution-only not-for-profit utilities benefit from the robust planning of their associated full-requirements not-for-profit wholesale utilities, who take on planning for supply adequacy on behalf of their distribution-and-transmission members. However, we believe some not-for-profit utilities will struggle to adapt to the new regulatory and operating environment. These include utilities that:

• Independently address long-term resource planning;
• Assume that aging fossil-fuel generators will be allowed to operate beyond state- and federal-level enacted mandates; or
• Undertake projects with low commercial feasibility before proper planning is complete, which could result in a withdrawal due to lack of funding or needed member buy-in.

The power grid will likely need to accommodate growing demand for beneficial electrification, including electric vehicles and demand from chip manufacturers, data centers, and crypto-currency miners.

Because reliability remains a prominent concern for policy makers, especially within less economically robust areas served by not-for-profit electric utilities, we observe an inclination to extend the operating lives of existing thermal units, which in our view could temper the imminent energy transition cost pressures consumers might otherwise face, but delay the implementation of decarbonization goals.

Related Research

• U.S. Public Power And Electric Cooperative Utilities 2024 Outlook: Mandates, Rising Costs, And Diminishing Affordability, Jan. 23, 2024
• Managing Renewables Risk Is Increasingly Integral To U.S. Power Utilities Credit Quality, Oct. 9, 2023