Myths vs. realities: Power markets, permitting & interconnection — what the evidence actually supports

The US interconnection queue held 2,600 GW of proposed generation and storage capacity at the end of 2024, roughly double the entire installed US generation fleet, yet only 14% of projects entering the queue between 2014 and 2023 reached commercial operation (Lawrence Berkeley National Laboratory, 2025). This staggering attrition rate sits at the center of a deeply misunderstood system, where myths about permitting timelines, market access, and grid capacity shape billions of dollars in investment decisions based on assumptions the evidence does not support.

Why It Matters

Power market reform, permitting acceleration, and interconnection queue management have become the binding constraints on US clean energy deployment. The Inflation Reduction Act allocated over $370 billion in clean energy incentives, but realizing those investments requires connecting projects to the grid through a process that currently takes an average of 5.1 years from initial application to commercial operation (LBNL, 2025). FERC Order 2023, finalized in mid-2024, mandated sweeping reforms to interconnection procedures, including cluster-based study processes, financial readiness deposits, and binding cost allocation timelines. These reforms are now being implemented across all seven US RTOs and ISOs.

For executives, the practical stakes are enormous. Corporate power purchase agreements (PPAs) for clean energy totaled 46 GW globally in 2024, with US buyers accounting for 24 GW (Clean Energy Buyers Association, 2025). But delivery risk on these agreements has increased sharply: 35% of PPAs signed in 2021-2022 experienced delays exceeding 12 months due to interconnection and permitting bottlenecks. Understanding what actually drives these delays, rather than accepting simplified narratives, is essential for managing energy procurement risk and capital allocation.

The consequences extend to grid reliability. NERC's 2025 Long-Term Reliability Assessment identified interconnection delays as a primary risk factor for resource adequacy across six of eight assessment areas, with potential capacity shortfalls of 30-50 GW by 2028 if queue attrition rates persist at current levels.

Key Concepts

Interconnection Queue is the formal process through which generation and storage projects apply to connect to the transmission grid. Managed by regional transmission organizations (RTOs) and independent system operators (ISOs), the queue involves feasibility studies, system impact studies, and facilities studies that assess whether the grid can accommodate new generation without compromising reliability. The queue has become the primary bottleneck: projects spend an average of 3.7 years in study phases before receiving a final interconnection agreement.

Network Upgrade Costs are the transmission system modifications (new transformers, line reconductoring, substation expansions) required to accommodate new generation. These costs are allocated to interconnecting generators and have escalated dramatically: the median network upgrade cost per MW for solar projects increased from $35,000 in 2018 to $110,000 in 2024, driven by grid congestion in high-renewable-penetration areas and aging infrastructure requiring concurrent replacement (LBNL, 2025).

Permitting encompasses federal, state, and local approvals required before construction, including environmental impact assessments (NEPA), wetlands permits (Clean Water Act Section 404), endangered species consultations, and local land use approvals. For transmission lines specifically, permitting involves securing rights-of-way across multiple jurisdictions, often requiring coordination among dozens of landowners, counties, and state agencies.

Capacity Markets are forward-looking auction mechanisms (operated by PJM, ISO-NE, and NYISO) that procure generation capacity to ensure resource adequacy. These markets have faced growing tension between their design, which historically favored dispatchable thermal generation, and the increasing penetration of variable renewable resources and storage that participate with different reliability characteristics.

Power Markets and Interconnection KPIs

Metric	Below Average	Average	Above Average	Top Quartile
Queue-to-Operation Timeline	>6 years	4-6 years	3-4 years	<3 years
Queue Completion Rate	<10%	10-18%	18-25%	>25%
Network Upgrade Cost ($/MW, solar)	>$150K	$80-150K	$40-80K	<$40K
Permitting Timeline (utility-scale solar)	>36 months	24-36 months	12-24 months	<12 months
Transmission Build Rate (circuit-miles/yr)	<500	500-900	900-1,500	>1,500
PPA Delivery Delay Rate	>40%	25-40%	10-25%	<10%

Myths vs. Reality

Myth 1: FERC Order 2023 will solve the interconnection backlog within two years

Reality: FERC Order 2023 introduces cluster-based studies, financial readiness deposits ($5,000/MW for generation, $2,000/MW for storage), and defined study timelines (150 days for cluster studies, 150 days for facilities studies). These reforms will reduce speculative applications and improve study throughput. However, the order does not address the fundamental physical constraints: insufficient transmission capacity in high-demand corridors, workforce shortages in transmission engineering (an estimated 3,500 unfilled positions across US utilities), and the 18-36 month procurement timelines for high-voltage transformers and other long-lead equipment (Department of Energy, 2025). PJM's initial transition to cluster studies cleared 38,000 MW of legacy applications in 2024-2025, but the remaining active queue still exceeds 250,000 MW. Realistic expectations suggest meaningful queue reduction will take 4-6 years, not two.

Myth 2: Permitting reform is primarily a federal issue

Reality: Federal NEPA review accounts for 12-18 months of permitting timelines for projects on federal lands, but the majority of utility-scale solar and wind projects are sited on private land where state and local approvals dominate. A Rhodium Group analysis found that 72% of permitting delays for renewable energy projects in 2023-2024 originated at the county or township level, driven by setback requirements, viewshed restrictions, decommissioning bond mandates, and outright moratoria. Over 180 US counties enacted restrictions on wind or solar development between 2022 and 2025, with concentrations in Ohio, Indiana, Virginia, and New York (Columbia Law School Sabin Center, 2025). The Fiscal Responsibility Act of 2023 streamlined some federal NEPA processes, but without parallel reforms at the state and local level, the overall permitting timeline has not meaningfully shortened.

Myth 3: Battery storage eliminates the need for new transmission

Reality: Battery storage provides critical grid services, including peak shaving, frequency regulation, and renewable integration, but it cannot substitute for transmission in moving power from resource-rich regions to load centers. A National Renewable Energy Laboratory study found that achieving 90% clean electricity by 2035 requires approximately 48,000 miles of new high-voltage transmission, even with aggressive storage deployment of 450 GW (NREL, 2025). Storage reduces curtailment at the local level but does not address the fundamental geographic mismatch between where renewables are most productive (Great Plains, Desert Southwest) and where electricity demand concentrates (coastal metropolitan areas). The two technologies are complementary, not substitutive. Projects pairing storage with generation do achieve lower network upgrade costs (20-35% reduction on average), making co-location a sound economic strategy, but framing storage as a transmission alternative misrepresents the physics of power delivery.

Myth 4: Wholesale electricity prices reflect the true cost of clean energy integration

Reality: Wholesale energy prices in US RTOs averaged $25-45/MWh in 2024, but these prices exclude several categories of integration costs that fundamentally alter the economics. Ancillary services costs (regulation, reserves, ramping) increased 35-60% across CAISO, SPP, and ERCOT between 2020 and 2024 as variable renewable penetration grew (Monitoring Analytics, 2025). Congestion costs in PJM exceeded $8.2 billion in 2024, a record driven by transmission constraints in areas with high renewable development. Capacity market clearing prices in PJM's 2025/2026 auction reached $269.92/MW-day, a 833% increase from the prior auction, reflecting reliability concerns as thermal plant retirements accelerate ahead of replacement capacity. When these costs are fully allocated, the system-level cost of integrating clean energy ranges from $8-15/MWh above the wholesale energy price, a material figure that executives must account for in long-term energy procurement strategies.

Myth 5: Interconnection costs are predictable at the time of application

Reality: Initial cost estimates provided in interconnection feasibility studies have historically understated final costs by 40-100%. A LBNL analysis of completed projects found that median cost escalation from initial estimate to final interconnection agreement was 68% for solar and 54% for wind. This occurs because early-stage studies use screening-level transmission models that do not fully capture interactions between projects in the same electrical area. As cluster studies proceed and cumulative impacts become visible, network upgrade requirements escalate. FERC Order 2023's shift to cluster studies should improve cost estimate accuracy by studying projects simultaneously, but the first cycle of cluster studies (2024-2026) will itself generate significant cost surprises as legacy projects encounter full-system modeling for the first time.

Myth 6: Siting projects near existing substations guarantees fast, low-cost interconnection

Reality: Proximity to substations provides advantages in reduced interconnection line costs, but the substation's hosting capacity and the upstream transmission network's available transfer capability are the binding constraints. Many substations in high-solar regions (Texas, California, Southeast) have reached thermal or voltage stability limits, requiring upstream reinforcements that cost $50-200 million regardless of the generator's physical proximity. The Midcontinent Independent System Operator (MISO) reported that 45% of projects applying to interconnect at existing substations in 2024 required network upgrades exceeding $10 million due to upstream constraints. Effective site selection requires transmission planning data analysis, not just geographic proximity to infrastructure.

Key Players

PJM Interconnection manages the largest US wholesale electricity market (65 million customers, 13 states plus DC) and is implementing FERC Order 2023 through its transition to cluster studies, having processed the first clearing of 38,000 MW of legacy projects.

NextEra Energy operates the largest US renewable energy portfolio (over 35 GW) and maintains dedicated interconnection and transmission development teams that consistently achieve above-average queue completion rates through strategic site selection and early engagement with transmission providers.

GridUnity provides software that models transmission hosting capacity and interconnection costs, enabling developers to screen sites for likely queue outcomes before committing development capital. Their platform is used by 8 of the 10 largest US renewable developers.

Pattern Energy has pioneered co-development of generation and transmission, with the SunZia transmission project (550 miles, 3,500 MW) connecting New Mexico wind resources to Arizona and California markets representing the largest clean energy infrastructure project under construction in the US.

Action Checklist

• Stress-test PPA delivery timelines assuming 18-24 month interconnection delays beyond contracted dates
• Require developers to provide transmission hosting capacity analysis, not just substation proximity, during site evaluation
• Budget for network upgrade cost escalation of 50-70% above initial feasibility study estimates
• Monitor FERC Order 2023 implementation milestones at your relevant RTO/ISO for cluster study timelines and deposit requirements
• Map county-level renewable energy ordinances in target development areas before committing site options
• Evaluate co-located storage to reduce network upgrade costs by 20-35% and improve queue competitiveness
• Engage directly with RTO/ISO planning staff to understand long-range transmission plan alignment with project locations
• Include full integration costs ($8-15/MWh above wholesale) in long-term energy procurement financial models

FAQ

Q: How long should executives realistically plan for when procuring renewable energy through PPAs? A: Plan for 4-6 years from PPA execution to first delivery for new-build projects, with contingency provisions for an additional 12-18 months. Projects with secured interconnection agreements and completed permitting can deliver in 18-24 months, but these represent a minority of available supply. Executives should prioritize PPAs with projects that have already progressed through interconnection studies (late-stage queue position) and hold all required permits, even if pricing is 5-10% higher than earlier-stage alternatives.

Q: What is the most reliable indicator that a project will actually reach commercial operation? A: The strongest predictor is whether the project has received a fully executed interconnection agreement with defined network upgrade costs and construction timelines. Projects with executed agreements complete at rates exceeding 70%, compared to under 14% for all projects entering the queue. Secondary indicators include secured land control, completed environmental permits, and executed equipment procurement contracts for long-lead items (transformers, inverters).

Q: How will FERC Order 2023 affect project costs and timelines for projects entering the queue today? A: Projects entering after FERC Order 2023 implementation will face higher upfront deposits ($5,000/MW for generation), shorter study timelines (theoretically 150 days per phase), and potentially more accurate cost estimates due to cluster-based analysis. However, the transition period (2024-2026) creates uncertainty as RTOs implement new procedures while simultaneously processing legacy backlogs. Expect the first full cycle of reformed studies to complete in 2026-2027, with reliable data on the reform's effectiveness available by late 2027.

Q: Should companies invest in behind-the-meter generation to avoid interconnection challenges? A: Behind-the-meter projects (rooftop solar, on-site storage) avoid wholesale interconnection queues but face their own constraints: distribution-level hosting capacity limits, utility interconnection study requirements (typically 60-180 days), and net metering policy uncertainty in many states. For loads under 5 MW, behind-the-meter solutions offer faster deployment (12-18 months) with more predictable costs. For larger loads, the economics favor wholesale PPAs despite interconnection risks, because utility-scale projects achieve 30-40% lower levelized costs than distributed generation.

Sources

• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection, 2025 Edition. Berkeley, CA: LBNL.
• Clean Energy Buyers Association. (2025). Deal Tracker: 2024 Annual Corporate Clean Energy Procurement Report. Washington, DC: CEBA.
• National Renewable Energy Laboratory. (2025). Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035. Golden, CO: NREL.
• Monitoring Analytics. (2025). State of the Market Report for PJM 2024. Eagleville, PA: Monitoring Analytics.
• Columbia Law School Sabin Center for Climate Change Law. (2025). Local Opposition to Renewable Energy Facilities in the United States. New York: Columbia University.
• US Department of Energy. (2025). National Transmission Needs Study: 2025 Update. Washington, DC: DOE.
• Rhodium Group. (2025). Clean Energy Permitting Tracker: Delays by Jurisdiction and Project Type. New York: Rhodium Group.