Grid's Waiting Room

The numbers tell a story of structural dysfunction. At the end of 2024, 2.6 terawatts of generation capacity sat waiting for grid access across US interconnection queues—more than double the country's entire installed generation fleet. Solar and storage account for 95% of those requests. Only 21% of projects entering queues between 2018 and 2022 ever reached commercial operation. The rest died waiting.

FERC Order 2023, issued in July 2023 and refined through Order 2023-A in March 2024, represents the commission's most ambitious attempt in two decades to unclog this bottleneck. One year into implementation, the results reveal both the promise and limits of procedural reform when the underlying infrastructure deficit remains unaddressed.

The Discipline Theory Meets Reality

Order 2023's core bet is straightforward: speculative projects clog the queue, drive serial restudies when they withdraw, and strand viable developments in procedural limbo. Financial discipline—higher deposits, site control requirements, milestone penalties - should filter out projects lacking genuine development intent.

Early evidence from MISO suggests the theory holds. The grid operator required $4,000/MW deposits for its 2024 cycle. Withdrawal rates plummeted to 12%, down from 45% in prior years. This is clearly a fundamental shift in who shows up to the queue.

The first-ready, first-served provisions compound this effect. Developers demonstrating site control, financing, and offtake agreements receive priority processing. Queue position alone - the currency of the old system - no longer guarantees anything. Development maturity now matters more than filing date.

But filtering out speculators doesn't create transmission capacity. PJM's first post-Order 2023 cluster study processed 1,247 projects totaling 298 GW—a volume exceeding the RTO's entire installed base. Median upgrade costs landed at $156/kW for solar and $203/kW for storage. For a 200 MW solar project, that's $31 million in network upgrades before construction begins. Many projects cannot absorb those economics.

The Queue That Dwarfs the Grid

The Queue That Dwarfs the Grid. Source: Berkeley Lab, 2024. Projects waiting for grid access now exceed double the entire US generation fleet.

Regional Divergence Deepens

Implementation reveals that interconnection dysfunction isn't uniform—it's geographic. MISO's 2024 Definitive Planning Phase completed in 14 months rather than the historical 36-month average. Affected System Study coordination with SPP added two months. That's progress.

CAISO tells a different story. The grid operator's 2024 cluster received 541 applications totaling 354 GW. Study completion dates extend to 2027. Order 2023 compliance did not immediately resolve the bottleneck—California's transmission constraints run deeper than procedural inefficiency.

The divergence matters for developers and investors making capital allocation decisions. MISO positions in relatively uncongested areas may clear in 18 months. CAISO positions with 2027 study dates carry three additional years of development risk, permitting exposure, and capital lockup. Same federal rule, radically different outcomes.

PJM occupies the middle ground—massive scale with meaningful reform. Commissioner Phillips and Commissioner Rosner noted in December 2024 that "PJM is undergoing the most significant interconnection process reform in its history," transitioning from first-come-first-served to cluster-based processing. The transition itself creates friction: projects caught between regimes face milestone recalculations and deposit adjustments that weren't part of their original development plans.

The Cost Allocation Fight Isn't Over

Network upgrade cost allocation remains the fault line that Order 2023 didn't fully address. FERC retained participant funding for most upgrade categories—interconnection customers pay for the transmission improvements their projects require. In congested corridors, that means individual projects face upgrade bills exceeding $500 million.

What's Waiting in Line

What's Waiting in Line. Source: Berkeley Lab. Clean energy dominates the backlog—and bears the brunt of interconnection delays.

CAISO's alternative approach allocates certain upgrade costs across the transmission access charge rather than assigning them entirely to interconnection customers. Individual project burdens shrink, but ratepayers absorb the difference. The methodology reflects California's policy choice to treat transmission as shared infrastructure enabling state climate goals.

Critics argue participant funding sends efficient price signals—projects should locate where the grid can accommodate them, not where transmission must be built to reach them. Proponents of cost socialization counter that transmission benefits all users and enables competition that ultimately lowers consumer costs. Both arguments have merit. Neither resolves the fundamental tension between individual project economics and system-wide optimization.

Affected System Study reform addresses a procedural pain point that previously allowed neighboring systems to delay studies indefinitely. Order 2023 imposes 90-day deadlines for study initiation and 120-day deadlines for completion. For projects near RTO boundaries—and there are many—this removes a source of unbounded timeline risk. Whether deadlines hold under real-world resource constraints remains to be tested.

What Other Markets Reveal

The UK offers the closest parallel experiment. Ofgem implemented queue management rules in 2022 requiring projects to demonstrate funding, planning consent, and equipment procurement. Non-compliant projects lose queue positions—a stricter standard than Order 2023's deposit-and-milestone approach.

Results appeared quickly. The UK queue dropped from 176 GW in 2022 to 97 GW in 2024. Average time from application to connection fell from 12 years to 6 years. The British experience suggests aggressive queue discipline can halve backlogs within two years—but also that interconnection reform alone cannot eliminate wait times measured in years.

MISO's Deposit Experiment Worked

MISO's Deposit Experiment Worked. Source: MISO 2024 cycle data. Higher financial stakes filtered out speculative projects, cutting withdrawals by nearly 75%.

China eliminated the interconnection queue problem through a fundamentally different model: centralized planning. State Grid Corporation identifies renewable energy bases and constructs associated transmission before generation develops. The 12 GW Zhangbei wind complex connected to Beijing load centers through dedicated ultra-high-voltage corridors planned years in advance. Generation follows transmission, not the reverse.

India faces comparable challenges at larger scale. The Central Electricity Regulatory Commission's 2023 reforms require state transmission utilities to proactively plan for renewable energy zones—shifting planning responsibility from developers to system operators. The approach acknowledges that interconnection dysfunction often reflects transmission planning failure rather than queue management deficiency.

The Planning Gap Order 2023 Can't Close

This points to the structural limitation embedded in FERC's reform. Order 2023 addresses queue procedures but not underlying transmission inadequacy. The US requires 47,000 to 57,000 miles of new high-voltage transmission by 2035 to meet stated decarbonization goals. Current construction rates total 1,500 miles annually. That arithmetic doesn't work.

FERC's pending Long-Term Transmission Planning rulemaking (Docket RM21-17) proposes requiring proactive planning for anticipated generation—the approach China and India have already adopted. If finalized, it would represent a more fundamental shift than Order 2023: treating transmission as infrastructure that enables generation development rather than an afterthought interconnection customers must finance project-by-project.

Until that rulemaking resolves, Order 2023 produces incremental gains in queue management efficiency while the underlying constraint—transmission capacity—binds ever tighter. Developers entering queues should anticipate higher upfront capital requirements, with deposits and readiness milestones requiring $50 million or more for utility-scale projects in congested areas. Affected System Study coordination still adds 6 to 12 months for projects near RTO boundaries. And network upgrade cost estimates remain volatile—final figures often double initial estimates, requiring contingency budgets sized accordingly.

The interconnection queue may be better managed. It is not solved. The 2.6 TW waiting for grid access represents the gap between America's clean energy ambitions and its transmission infrastructure reality. Order 2023 resequenced the line. It didn't shorten it.