Introduction
The US transmission grid is the critical bottleneck constraining every aspect of the power sector: new generation cannot connect to the grid, renewable energy projects wait years in interconnection queues, data centers cannot secure power delivery, and existing generation assets in constrained regions command premium valuations precisely because new supply cannot easily enter the market. The transmission infrastructure deficit is not a temporary condition; it is a structural feature of the US power system that will persist for years and drive hundreds of billions of dollars in investment, M&A, and financing activity that energy bankers will advise on.
Much of the US transmission system was built in the 1960s through 1980s and has not been expanded at a pace that matches the evolution of the generation mix and demand patterns. The system was designed for a world of large, centralized coal and nuclear plants located near demand centers. Today's power system requires moving electricity from remote wind farms in the Great Plains and solar installations in the desert Southwest to population centers hundreds of miles away, while simultaneously expanding capacity to serve concentrated new loads from data centers and industrial facilities. This mismatch between grid design and grid requirements is the root cause of the transmission bottleneck.
The Interconnection Queue Crisis
The interconnection queue is the process through which new generation projects apply to connect to the transmission grid. To generate electricity and sell it into wholesale markets, a power plant must complete an interconnection study (determining what grid upgrades are needed to accommodate the new generation), pay for its share of those upgrades, and receive permission to connect. This process has become the single greatest obstacle to new power supply in the US.
- Interconnection Queue
The backlog of generation projects (solar, wind, gas, battery storage, nuclear) that have submitted applications to connect to the transmission grid but have not yet completed the interconnection study and upgrade process. As of 2025, the total interconnection queue across all US ISOs/RTOs exceeds 2,500 GW of proposed capacity, representing many multiples of the approximately 1,200 GW of total installed US generation capacity. Average wait times in the queue range from 4-7 years, and completion rates are low (historically, only 15-25% of projects that enter the queue ultimately reach commercial operation).
The queue backlog reflects several compounding problems:
- Volume overwhelm. The combination of renewable energy development (driven by IRA tax credits), new gas generation (driven by data center demand), and battery storage projects has flooded queues with applications far exceeding the transmission providers' study capacity.
- Serial study process. Traditionally, interconnection studies were conducted sequentially: when one project dropped out, the studies for all subsequent projects had to be revised, creating a cascading delay cycle.
- Cost uncertainty. Network upgrade costs assigned to interconnecting generators can run into hundreds of millions of dollars, often changing dramatically between initial estimates and final cost allocations, causing developers to withdraw and restart the cycle.
FERC Order 1920: Reforming Transmission Planning
In May 2024, FERC issued Order No. 1920, the most significant transmission planning reform in over a decade. The order addresses the systemic failure of the existing planning framework, which focused primarily on near-term reliability needs rather than long-term system expansion.
Key provisions of Order 1920 include:
- 20-year planning horizon. Transmission providers must plan for anticipated needs over a 20-year period, rather than the shorter horizons previously used. This forward-looking approach ensures that transmission is built to accommodate projected load growth, generation changes, and policy-driven resource shifts.
- Interconnection-related needs. The order requires planners to consider transmission needs identified repeatedly in interconnection studies but never addressed, closing the gap between interconnection bottlenecks and transmission planning.
- Grid-enhancing technologies. Planners must evaluate grid-enhancing technologies (dynamic line ratings, advanced conductors, power flow control devices) as alternatives or complements to new transmission line construction, potentially accelerating capacity expansion at lower cost.
- Cost allocation. The order establishes frameworks for allocating transmission costs across benefiting regions, addressing the historically contentious question of who pays for new transmission.
The Investment Opportunity
Total US utility capital expenditure is projected at $1.4 trillion from 2025 to 2030, roughly double the prior decade's investment, with transmission and distribution representing the largest growth categories. Global grid investment is expected to top $470 billion in 2025 alone. This investment wave creates significant advisory and financing opportunities for energy bankers.
Investment Categories
| Category | Description | Key Beneficiaries |
|---|---|---|
| New long-distance lines | Connecting remote wind/solar to demand centers | Transmission developers, utilities |
| Grid reinforcement | Upgrading existing lines and substations for higher capacity | Regulated utilities |
| Interconnection infrastructure | Building the lines and substations needed to connect new generation | Developers, utilities, ISOs |
| Advanced conductors | Replacing existing conductors with advanced materials that carry 2-3x more power | Technology companies, utilities |
| Transformer replacement | Replacing aging and undersized transformers (24-36 month lead times) | Equipment manufacturers, utilities |
Among these investment categories, equipment supply chains present their own constraints that limit the pace of grid expansion.
Transmission in Energy Banking
For energy investment bankers, the transmission theme manifests in several ways:
Utility capital advisory and financing. Utilities are raising tens of billions annually in debt and equity to fund transmission and distribution investment. These capital raises require banking advisory on capital structure optimization, market timing, and instrument selection.
Rate case strategy. Transmission investment drives rate case filings as utilities seek to recover their capital expenditures through customer rates. Bankers advise on rate case strategy, ROE testimony, and the financial implications of regulatory outcomes.
M&A involving transmission assets. Transmission companies and utilities with significant transmission operations trade at premium valuations reflecting the defensive, FERC-regulated nature of these assets and the growth embedded in their capital plans.
Project finance. Large transmission projects developed by independent transmission companies or utility joint ventures may use project finance structures, particularly for cross-border or long-distance lines that span multiple jurisdictions.
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